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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. 14 TO
MARKET MAKING PROSPECTUS DATED
APRIL 16, 2009
THE DATE OF THIS SUPPLEMENT IS FEBRUARY 23, 2010
On February 19, 2010, 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, 2009
— 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 | 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 18, 2010, there were 1,668,665,133 shares of common stock outstanding, without par value, 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”), EFC Holdings, Intermediate Holding, 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 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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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 | |
| 2008 Form 10-K | EFH Corp.’s Annual Report on Form 10-K for the year ended December 31, 2008 as recast in a Current Report on Form 8-K filed on May 20, 2009 to reflect the adoption of new accounting and disclosure guidance related to noncontrolling interests | |
| Adjusted EBITDA | Adjusted EBITDA means EBITDA adjusted to exclude non-cash items, unusual items and other adjustments allowable under certain of our debt arrangements. See the definition of EBITDA below. Adjusted EBITDA and EBITDA are not recognized terms under GAAP and, thus, are non-GAAP financial measures. We are providing Adjusted EBITDA in this Form 10-K (see reconciliation in Exhibit 99(b) and 99(c)) solely because of the important role that Adjusted EBITDA plays in respect of certain covenants contained in our debt arrangements. We do not intend for Adjusted EBITDA (or EBITDA) to be an alternative to net income as a measure of operating performance or an alternative to cash flows from operating activities as a measure of liquidity or an alternative to any other measure of financial performance presented in accordance with GAAP. Additionally, we do not intend for Adjusted EBITDA (or EBITDA) to be used as a measure of free cash flow available for management’s discretionary use, as the measure excludes certain cash requirements such as interest payments, tax payments and other debt service requirements. Because not all companies use identical calculations, our presentation of Adjusted EBITDA (and EBITDA) may not be comparable to similarly titled measures of other companies. | |
| Ancillary services | Refers to services necessary to support the transmission of energy and maintain reliable operations for the entire transmission system. | |
| CAIR | Clean Air Interstate Rule | |
| Capgemini | Capgemini Energy LP, a provider of business support services to EFH Corp. and its subsidiaries | |
| CO2 | carbon dioxide | |
| Competitive Electric segment | Refers to the EFH Corp. business segment that consists principally of TCEH. | |
| CREZ | Competitive Renewable Energy Zone | |
| DOE | US Department of Energy | |
| EBITDA | Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization. See the definition of Adjusted EBITDA above. | |
| EFC Holdings | Refers to Energy Future Competitive Holdings Company, a direct subsidiary of EFH Corp. and the direct parent of TCEH. | |
| EFH Corp. | Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include TCEH and Oncor. | |
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| EFH Corp. Senior Notes | Refers collectively to EFH Corp.’s 10.875% Senior Notes due November 1, 2017 (EFH Corp. 10.875% Notes) and EFH Corp.’s 11.25%/12.00% Senior Toggle Notes due November 1, 2017 (EFH Corp. Toggle Notes). | |
| EFH Corp. 9.75% Notes | Refers to EFH Corp.’s 9.75% Senior Secured Notes due October 15, 2019. | |
| EFIH Finance | Refers to EFIH Finance Inc., a direct, wholly-owned subsidiary of Intermediate Holding, formed for the sole purpose of serving as co-issuer with Intermediate Holding of certain debt securities. | |
| EFIH Notes | Refers to Intermediate Holding’s and EFIH Finance’s 9.75% Senior Secured Notes due October 15, 2019. | |
| EPA | US Environmental Protection Agency | |
| EPC | engineering, procurement and construction | |
| ERCOT | Electric Reliability Council of Texas, the independent system operator and the regional coordinator of various electricity systems within Texas | |
| ERISA | Employee Retirement Income Security Act of 1974, as amended | |
| FASB | Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting | |
| FERC | US Federal Energy Regulatory Commission | |
| Fitch | Fitch Ratings, Ltd. (a credit rating agency) | |
| GAAP | generally accepted accounting principles | |
| GHG | greenhouse gas | |
| GWh | gigawatt-hours | |
| Intermediate Holding | Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings. | |
| IRS | US Internal Revenue Service | |
| kV | kilovolts | |
| kWh | kilowatt-hours | |
| LIBOR | London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market. | |
| Luminant | Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas. | |
| Market heat rate | Heat rate is a measure of the efficiency of converting a fuel source to electricity. Market heat rate is the implied relationship between wholesale electricity prices and natural gas prices and is calculated by dividing the wholesale market price of electricity, which is based on the price offer of the marginal supplier in ERCOT (generally natural gas plants), by the market price of natural gas. Forward wholesale electricity market price quotes in ERCOT are generally limited to two or three years; accordingly, forward market heat rates are generally limited to the same time period. Forecasted market heat rates for time periods for which market price quotes are not available are based on fundamental economic factors and forecasts, including electricity supply, demand growth, capital costs associated with new construction of generation supply, transmission development and other factors. | |
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| Merger | The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007. | |
| Merger Agreement | Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp. | |
| Merger Sub | Texas Energy Future Merger Sub Corp, a Texas corporation and a wholly-owned subsidiary of Texas Holdings that was merged into EFH Corp. on October 10, 2007 | |
| MMBtu | million British thermal units | |
| Moody’s | Moody’s Investors Services, Inc. (a credit rating agency) | |
| MW | megawatts | |
| MWh | megawatt-hours | |
| NERC | North American Electric Reliability Corporation | |
| NOx | nitrogen oxide | |
| NRC | US Nuclear Regulatory Commission | |
| Oncor | Refers to Oncor Electric Delivery Company LLC, a direct majority-owned subsidiary of Oncor Holdings and an indirect subsidiary of EFH Corp., and/or its consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context, that is engaged in regulated electricity transmission and distribution activities. | |
| Oncor Holdings | Refers to Oncor Electric Delivery Holdings Company LLC, a direct wholly-owned subsidiary of Intermediate Holding and the direct majority owner of Oncor, that is consolidated as a variable interest entity under consolidations accounting standards. | |
| Oncor Ring-Fenced Entities | Refers to Oncor Holdings and its direct and indirect subsidiaries, including Oncor. | |
| OPEB | other postretirement employee benefits | |
| PUCT | Public Utility Commission of Texas | |
| PURA | Texas Public Utility Regulatory Act | |
| Purchase accounting | The purchase method of accounting for a business combination as prescribed by GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill. | |
| Regulated Delivery segment | Refers to the EFH Corp. business segment, which consists of the operations of Oncor. | |
| REP | retail electric provider | |
| RRC | Railroad Commission of Texas, which among other things, has oversight of lignite mining activity in Texas | |
| S&P | Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies Inc. (a credit rating agency) | |
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| SARs | Stock Appreciation Rights | |
| SARs Plan | Refers to the Oncor Electric Delivery Company Stock Appreciation Rights Plan | |
| SEC | US Securities and Exchange Commission | |
| Securities Act | Securities Act of 1933, as amended | |
| SG&A | selling, general and administrative | |
| SO2 | sulfur dioxide | |
| Sponsor Group | Collectively, the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P. (KKR), TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman Sachs & Co. (See Texas Holdings below.) | |
| TCEH | Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of EFC Holdings and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context, that are engaged in electricity generation and wholesale and retail energy markets activities. Its major subsidiaries include Luminant and TXU Energy. | |
| TCEH Finance | Refers to TCEH Finance, Inc., a direct, wholly-owned subsidiary of TCEH, formed for the sole purpose of serving as co-issuer with TCEH of certain debt securities. | |
| TCEH Senior Notes | Refers collectively to TCEH’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes Series B due November 1, 2015 (collectively, TCEH 10.25% Notes) and TCEH’s 10.50%/11.25% Senior Toggle Notes due November 1, 2016 (TCEH Toggle Notes). | |
| TCEH Senior Secured Facilities | Refers collectively to the TCEH Initial Term Loan Facility, TCEH Delayed Draw Term Loan Facility, TCEH Revolving Credit Facility, TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility. See Note 12 to the Financial Statements for details of these facilities. | |
| TCEQ | Texas Commission on Environmental Quality | |
| Texas Holdings | Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp. | |
| Texas Holdings Group | Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities. | |
| Texas Transmission | Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of its subsidiaries or any member of the Sponsor Group. | |
| TXU Energy | Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT. | |
| TXU Europe | TXU Europe Limited, a subsidiary of EFH Corp. that is in administration (similar to bankruptcy) in the United Kingdom | |
| TXU Fuel | TXU Fuel Company, a former subsidiary of TCEH | |
| TXU Gas | TXU Gas Company, a former subsidiary of EFH Corp. | |
| US | United States of America | |
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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, TCEH and/or its subsidiaries, or Oncor and/or its subsidiary as apparent in the context. See “Glossary” for other defined terms.
EFH Corp. Business and Strategy
We are a Dallas-based energy company with a portfolio of competitive and regulated energy businesses in Texas. EFH Corp. is a holding company conducting its operations principally through its subsidiaries, TCEH and Oncor. TCEH is wholly-owned, and EFH Corp. holds an approximately 80% interest in Oncor. Immediately below is an organization chart of the major 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 17,519 MW of generation capacity in Texas, which consists of lignite/coal, nuclear and natural gas-fueled generation facilities, including two new lignite-fueled units that achieved substantial completion (as defined in the EPC agreements for the units) in fall of 2009. In addition, TCEH is the largest purchaser of wind-generated electricity in Texas and the fifth largest in the US. TCEH is currently constructing one additional lignite/coal-fueled generation unit in Texas. This unit, which is in the commissioning and start-up phase, synchronized to the grid in January 2010 and is expected to achieve substantial completion (as defined in the EPC Agreement for the unit) in mid-2010. TCEH provides competitive electricity and related services to more than 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 117,000 miles of transmission and distribution lines. A significant portion of Oncor’s revenues represent fees for delivery services provided to TCEH. Distribution revenues from TCEH represented 38% and 39% of Oncor’s total revenues for the years ended December 31, 2009 and 2008, respectively.
EFH Corp. and Oncor have implemented certain structural and operational “ring-fencing” measures based on commitments made by Texas Holdings and Oncor to the PUCT that are intended to enhance the credit quality of Oncor. These measures serve to mitigate Oncor’s and Oncor Holdings’ credit exposure to the Texas Holdings Group and to reduce the risk that the assets and liabilities of Oncor or Oncor Holdings would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities. See Note 1 to Financial Statements for a description of the material features of these “ring-fencing” measures.
At December 31, 2009, we had approximately 9,030 full-time employees, including approximately 2,730 employees under collective bargaining agreements.
EFH Corp.’s Market
We operate primarily within the ERCOT market. This market represents approximately 85% of electricity consumption in Texas. ERCOT is the regional reliability coordinating organization for member electricity systems in Texas and the system operator of the interconnected transmission grid for those systems. ERCOT’s membership consists of more than 300 corporate and associate members, including electric cooperatives, municipal power agencies, independent generators, independent power marketers, investor-owned utilities, REPs and consumers.
The ERCOT market is currently divided into four regions or congestion management zones (North, Houston, South and West), which reflect transmission constraints that are commercially significant and which have limits as to the amount of electricity that can flow across zones. These constraints and zonal differences can result in differences between wholesale power prices among zones. Of TCEH’s baseload (coal- and nuclear-fueled) generation units, 12 (including the unit under construction) are located in the North zone, and two are located in the South zone. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulation and Rates — Wholesale Market Design” for discussion of ERCOT’s planned implementation of a nodal market design by December 2010.
The ERCOT market operates under reliability standards set by the NERC. The PUCT has primary jurisdiction over the ERCOT market to ensure adequacy and reliability of power supply across Texas’s main interconnected transmission grid. The ERCOT independent system operator is responsible for maintaining reliable operations of the bulk electricity supply system in the market. Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike certain other regional power markets, the ERCOT market is not a centrally dispatched power pool, and the ERCOT independent system operator does not procure energy on behalf of its members, except to the extent that it acquires ancillary services as agent for market participants. Members who sell and purchase power are responsible for contracting sales and purchases of power with other members through bilateral transactions. The ERCOT independent system operator also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.
Oncor, along with other owners of transmission and distribution facilities in Texas, assists the ERCOT independent system operator in its operations. Oncor has planning, design, construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated distribution service area. Oncor participates with the ERCOT independent system operator and other ERCOT utilities in obtaining regulatory approvals and planning, designing and constructing new transmission lines in order to remove existing constraints on the ERCOT transmission grid. The transmission lines are necessary to meet reliability needs, support renewable energy production and increase bulk power transfer capability.
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The following data is derived from information published by ERCOT:
From 1999 through September 2009, over 41,000 MW of mostly natural gas-fueled and wind generation capacity has been developed in the ERCOT market. Installed generation capacity in the ERCOT market totals approximately 84,000 MW, including approximately 3,000 MW mothballed (idled) capacity, as well as wind (over 9,000 MW), water and other resources that may not be available coincident with system need. In 2009, hourly demand peaked at a record 63,400 MW. ERCOT’s estimate of total available capacity for 2010 reserve margin calculation is approximately 76,000 MW of which, approximately 66% is natural gas-fueled generation and approximately 33% is lignite/coal and nuclear-fueled baseload generation. ERCOT currently has a target reserve margin level of 12.5%; the reserve margin is projected by ERCOT to be 21.8% in 2010, 19.9% in 2011, and drop below the target reserve margin, to 12.3% by 2014. Reserve margin is the difference between system generation capability and anticipated peak load.
The ERCOT market has limited interconnections to other markets in the US, which currently limits potential imports into and exports out of the ERCOT market to 1,106 MW of generation capacity (or approximately 2% of peak demand). In addition, wholesale transactions within the ERCOT market are generally not subject to regulation by the FERC.
Natural gas-fueled generation is the predominant electricity capacity resource in the ERCOT market and accounted for approximately 42% of the electricity produced in the ERCOT market in 2009. Because of the significant natural gas-fueled capacity and the ability of such facilities to more readily increase or decrease production when compared to baseload generation, marginal demand for electricity is usually met by natural gas-fueled facilities. As a result, wholesale electricity prices in ERCOT are highly correlated with natural gas prices.
EFH Corp.’s Strategies
Each of our businesses focuses its operations on key drivers for that business, as described below:
| • | TCEH focuses on optimizing and developing its generation fleet to safely provide reliable electricity supply in a cost-effective manner, hedging its electricity price risk and providing high quality service and innovative energy products to retail and wholesale customers. |
| • | Oncor focuses on delivering electricity in a safe and reliable manner, minimizing service interruptions and investing in its transmission and distribution infrastructure to maintain its system, serve its growing customer base with a modernized grid and support renewable energy production. |
Other elements of our strategies include:
| • | Increase value from existing business lines. Our strategy focuses on striving for top quartile or better performance across our operations in terms of safety, reliability, cost and customer service. In establishing tactical objectives, we incorporate the following core operating principles: |
| • | Safety: Placing the safety of communities, customers and employees first; |
| • | Environmental Stewardship: Continuing to make strategic and operational improvements that lead to cleaner air, land and water; |
| • | Customer Focus: Delivering products and superior service to help customers more effectively manage their use of electricity; |
| • | Community Focus: Being an integral part of the communities in which we live, work and serve; |
| • | 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 a commodity risk management strategy. The strong historical correlation between natural gas prices and wholesale electricity prices in the ERCOT market provides us an opportunity to manage our exposure to variability of wholesale electricity prices. We have established a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments, and as of December 31, 2009, has effectively sold forward approximately 1.6 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 200,000 GWh at an assumed 8.0 market heat rate) for the period January 1, 2010 through December 31, 2014 at weighted average annual hedge prices ranging from $7.80 per MMBtu to $7.19 per MMBtu. These transactions, as well as forward power sales, have effectively hedged an estimated 68% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning January 1, 2010 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which 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, 2009, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility discussed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Financial Condition — Liquidity and Capital Resources — Liquidity Effects of Commodity Hedging and Trading Activities”), thereby reducing the cash and letter of credit collateral requirements for the hedging program. |
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| • | Pursue new environmental initiatives. We are committed to continue to operate in compliance with all environmental laws, rules and regulations and to reduce our impact on the environment. EFH Corp.’s Sustainable Energy Advisory Board advises in the pursuit of technology development opportunities that reduce our impact on the environment while balancing the need to help address the energy requirements of Texas. The Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: the environment, labor unions, customers, economic development in Texas and technology/reliability standards. In addition, we are focused on and are pursuing opportunities to reduce emissions from our existing and new lignite/coal-fueled generation units in the ERCOT market. We have voluntarily committed to reduce emissions of mercury, 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, 2009, we invested a total of $145 million in these programs. |
Seasonality
Our revenues and results of operations are subject to seasonality, weather conditions and other electricity usage drivers, with revenues being highest in the summer.
Operating Segments
We have aligned and report our business activities as two operating segments: the Competitive Electric segment (primarily represented by TCEH) and the Regulated Delivery segment (primarily represented by Oncor). See Note 24 to Financial Statements for additional financial information for the segments.
Competitive Electric Segment
Key management activities, including commodity risk management, are performed on an integrated basis. However, for purposes of operational accountability, performance management and market identity, the segment operations have been grouped into Luminant, which is engaged in electricity generation and wholesale markets activities, and TXU Energy, which is engaged in retail electricity sales activities. These activities are conducted through separate legal entities.
Luminant — Luminant’s existing electricity generation fleet consists of 18 plants in Texas with total installed nameplate generating capacity as shown in the table below:
Fuel Type | Installed Nameplate Capacity (MW) | Number of Plants | Number of Units (a) | |||
Nuclear | 2,300 | 1 | 2 | |||
Lignite/coal (b) | 7,217 | 5 | 11 | |||
Natural gas (c)(d) | 8,002 | 12 | 35 | |||
Total | 17,519 | 18 | 48 | |||
(a) Leased units consist of six natural gas-fueled units totaling 390 MW of capacity. All other units are owned. (b) Does not include generation capacity of the second unit at Oak Grove, currently under construction, as discussed below under “Lignite/Coal-Fueled Generation Operations.” (c) Includes 1,953 MW representing seven units mothballed and not currently available for dispatch and 655 MW representing two units operated under reliability-must-run (RMR) contracts with ERCOT. See “Natural Gas-Fueled Generation Operations” below. (d) Includes 1,528 MW representing 12 units currently operated for unaffiliated parties. | ||||||
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The generation plants are located primarily on land owned in fee. Nuclear and lignite/coal-fueled (baseload) plants are generally scheduled to run at capacity except for periods of scheduled maintenance activities or, in the case of lignite/coal units, backdown due to periods of low wholesale power prices (i.e., economic backdown) or ERCOT instruction. The natural gas-fueled generation units supplement the baseload generation capacity in meeting consumption in peak demand periods as production from a certain number of these units can more readily be ramped up or down as demand warrants.
Nuclear Generation Operations — Luminant operates two nuclear generation units at the Comanche Peak plant, each of which is designed for a capacity of 1,150 MW. Comanche Peak’s Unit 1 and Unit 2 went into commercial operation in 1990 and 1993, respectively, and are generally operated at full capacity to meet the load requirements in ERCOT. Refueling (nuclear fuel assembly replacement) outages for each unit are scheduled to occur every eighteen months during the spring or fall off-peak demand periods. Every three years, the refueling cycle results in the refueling of both units during the same year, which last occurred in 2008. While one unit is undergoing a refueling outage, the remaining unit is intended to operate at full capacity. During a refueling outage, other maintenance, modification and testing activities are completed that cannot be accomplished when the unit is in operation. Over the last three years, excluding the 55-day outage in 2007 to refuel and replace the steam generators and reactor vessel head in Unit 1, the refueling outage period per unit has ranged from 19 to 27 days. The Comanche Peak plant operated at a capacity factor of 93.5% in 2007, reflecting the planned extended refueling outage to replace the steam generator and reactor vessel head in Unit 1, 95.2% in 2008, reflecting refueling of both units and 100.0% in 2009.
Luminant has contracts in place for all of its nuclear fuel conversion services through 2011 and 77% of its requirements through 2015. In addition, Luminant has contracts for the acquisition of approximately 80% of its uranium requirements for 2010 (with contracts for the remainder substantially complete) and 64% of its requirements through 2014, all of its nuclear fuel enrichment services through 2012 and all of its nuclear fuel fabrication services through 2018.
Contracts for the acquisition of additional raw uranium and nuclear fuel conversion services through 2024 and 2029, respectively, are being negotiated. Luminant does not anticipate any significant difficulties in acquiring raw uranium and contracting for associated conversion services and enrichment in the foreseeable future.
Luminant believes its on-site used nuclear fuel storage capability is sufficient for a minimum of three years. The nuclear industry is continuing to review ways to enhance security of used-fuel storage with the NRC to fully utilize physical storage capacity. Current on-site used nuclear fuel storage capability will require the use of the industry technique of dry cask storage within the next three years.
The Comanche Peak nuclear generation units have an estimated useful life of 60 years from the date of commercial operation. Therefore, assuming that Luminant receives 20-year license extensions, similar to what has been granted by the NRC to several other commercial generation reactors over the past several years, plant decommissioning activities would be scheduled to begin in 2050 for Comanche Peak Unit 1 and 2053 for Unit 2 and common facilities. Decommissioning costs will be paid from a decommissioning trust that, pursuant to state law, is funded from Oncor’s customers through an ongoing delivery surcharge. (See Note 19 to Financial Statement for discussion of the decommissioning trust fund.)
Nuclear insurance provisions are discussed in Note 13 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.
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In March 2009, the NRC announced an official review schedule for the license application. Based on the schedule, the NRC expects to complete its review by December 2011, and it is expected that a license would be issued approximately one year later. In November 2009, CPNPC filed a comprehensive revision to the license application that updated the license application for developments occurring after the initial filing.
In 2009, the DOE announced that it had selected four applicants to proceed to the due diligence phase of its Loan Guarantee Program and to commence negotiations towards potential loan guarantees for their respective generation projects. CPNPC was not among the initial four applicants selected by the DOE; however, CPNPC continues to update the DOE on its progress, with the goal of securing a DOE loan guarantee for financing the proposed units prior to commencement of construction.
Lignite/Coal-Fueled Generation Operations — Luminant’s lignite/coal-fueled generation fleet capacity totals 7,217 MW (including two recently completed new units) and consists of the Big Brown (2 units), Monticello (3 units), Martin Lake (3 units), Oak Grove (1 unit) and Sandow (2 units) plants. These plants are generally operated at full capacity to help meet the load requirements in ERCOT. Maintenance outages are scheduled during off-peak demand periods. Over the last three years, the total annual scheduled and unscheduled outages per unit averaged 31 days. Luminant’s lignite/coal-fueled generation fleet operated at a capacity factor of 90.9% in 2007, 87.6% in 2008 and 86.5% in 2009, which represents top quartile performance of US coal-fueled generation facilities. The 2008 performance reflects extended unplanned outages at several units, and the 2009 performance reflects increased economic backdown of the units.
Luminant is nearing completion of a program to develop and construct three lignite-fueled generation units with a total estimated capacity of 2,200 MW. The three units consist of one unit at a leased site that is adjacent to an existing owned lignite-fueled generation unit (Sandow) and two units at an owned site (Oak Grove). The Sandow unit and the first Oak Grove unit achieved substantial completion (as defined in the EPC Agreements for the respective units) effective September 30, 2009 and December 22, 2009, respectively. Accordingly, the company has operational control of these units. The second Oak Grove unit, which is in the commissioning and start-up phase, synchronized to the grid in January 2010 and is expected to achieve substantial completion (as defined in the EPC Agreement for the unit) in mid-2010.
Aggregate cash capital expenditures for these three units are expected to total approximately $3.25 billion including all construction, site preparation and mining development costs, of which approximately $3.1 billion was spent as of December 31, 2009. The investment includes approximately $500 million for state-of-the-art emissions controls for the three new units. Including capitalized interest and the step-up in construction work-in-process balances to fair value as a result of purchase accounting for the Merger in 2007, carrying value of the units are estimated to total approximately $4.8 billion upon completion. Agreements were executed with EPC contractors Bechtel Power Corporation and Fluor Enterprises, Inc. to engineer and construct the units at Sandow and Oak Grove, respectively.
Luminant also has an environmental retrofit program under which it plans to install additional environmental control systems at its existing lignite/coal-fueled generation facilities. Capital expenditures associated with these additional environmental control systems could exceed $1.0 billion, of which $326 million was spent through 2009. Luminant has not yet completed all detailed cost and engineering studies for the additional environmental systems, and the cost estimates could change materially as it determines the details of and further evaluates the engineering and construction costs related to these investments.
Approximately 47% of the fuel used at Luminant’s lignite/coal-fueled generation plants in 2009 was supplied from lignite reserves owned in fee or leased surface-minable deposits dedicated to the Big Brown, Monticello, Martin Lake and Oak Grove plants, which were constructed adjacent to the reserves. Luminant owns in fee or has under lease an estimated 843 million tons of lignite reserves dedicated to its generation plants and 241 million tons associated with an undivided interest in the lignite mine that provides fuel for the Sandow facility. Luminant also owns in fee or has under lease in excess of 85 million tons of reserves not currently dedicated to specific generation plants. In 2009, Luminant recovered approximately 20 million tons of lignite to fuel its generation plants. Luminant utilizes owned and/or leased equipment to remove the overburden and recover the lignite.
Luminant’s lignite mining operations include extensive reclamation activities that return the land to productive uses such as wildlife habitats, commercial timberland and pasture land. In 2009, Luminant reclaimed 1,485 acres of land. In addition, Luminant planted more than 1.1 million trees in 2009, the majority of which were part of the reclamation effort.
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Luminant supplements its lignite fuel at Big Brown, Monticello and Martin Lake with western coal from the Powder River Basin in Wyoming. The coal is purchased from multiple suppliers under contracts of various lengths and is transported from the Powder River Basin to Luminant’s generation plants by railcar. Based on its current usage, Luminant believes that it has sufficient lignite reserves for the foreseeable future and has contracted approximately 80% of its western coal resources and all of the related transportation through 2011.
Natural Gas-Fueled Generation Operations — Luminant’s fleet of 35 natural gas-fueled generation units totaling 8,002 MW of capacity includes 3,866 MW of currently available capacity, 2,183 MW of capacity being operated for unaffiliated third parties (including 655 MW under RMR agreements with ERCOT), and 1,953 MW of capacity currently mothballed (idled). The natural gas-fueled units predominantly serve as peaking units that can be ramped up or down as demand for electricity warrants.
Wholesale Operations — Luminant’s wholesale operations play a pivotal role in our competitive business portfolio by optimally dispatching the generation fleet, including the baseload facilities, sourcing TXU Energy’s and other customers’ electricity requirements and managing commodity price risk.
Our commodity price exposure is managed across the complementary Luminant generation and TXU Energy retail businesses on a portfolio basis. Under this approach, Luminant’s wholesale operations manage the risks of imbalances between generation supply and sales load, which primarily represent exposures to natural gas price movements and market heat rate changes (variations in the relationships between natural gas prices and wholesale electricity prices), through wholesale markets activities that include physical purchases and sales and transacting in financial instruments.
Luminant’s wholesale operations manage this commodity price and heat rate exposure through asset management and hedging activities. These operations provide TXU Energy and other retail and wholesale customers with electricity and related services to meet their demands and the operating requirements of ERCOT. Luminant also sells forward generation and seeks to maximize the economic value of the generation fleet, particularly the baseload facilities. In consideration of operational production and customer consumption levels that can be highly variable, as well as opportunities for long-term purchases and sales with large wholesale market participants, Luminant buys and sells electricity in short-term transactions and executes longer-term forward electricity purchase and sales agreements. Luminant is the largest purchaser of wind-generated electricity in Texas and the fifth largest in the US with more than 900 MW of existing wind power under contract.
In its hedging activities, Luminant enters into contracts for the physical delivery of electricity and natural gas, exchange traded and “over-the-counter” financial contracts and bilateral contracts with producers, generators and end-use customers. A major part of these hedging activities is a long-term hedging program, described above under “EFH Corp.’s Strategies”, designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, principally utilizing natural gas-related financial instruments.
The wholesale operations also dispatch Luminant’s available natural gas-fueled generation capacity. Luminant’s dispatching activities are performed through a centrally managed real-time operational staff that synthesizes operational activities across the fleet and interfaces with various wholesale market channels. Luminant’s wholesale operations coordinate the overall commercial strategy for these plants working closely with other Luminant operations. In addition, the wholesale operations manage the natural gas and fuel-oil procurement requirements for Luminant’s natural gas-fueled generation fleet.
Luminant’s wholesale operations engage in commercial operations such as physical purchases, storage and sales of natural gas, electricity and natural gas trading and third-party energy management. Natural gas operations include direct purchases from natural gas producers, transportation agreements, storage leases and commercial retail sales. Luminant currently manages approximately 11 billion cubic feet of natural gas storage capacity.
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Luminant’s wholesale operations manage exposure to wholesale commodity and credit-related risk within established transactional risk management policies, limits and controls. These policies, limits and controls have been structured so that they are practical in application and consistent with stated business objectives. Risk management processes include capturing transactions, performing and validating valuations and reporting exposures on a daily basis using risk management information systems designed to support a large transactional portfolio. A risk management forum meets regularly to ensure that business practices comply with approved transactional limits, commodities, instruments, exchanges and markets. Transactional risks are monitored and limits are enforced to comply with the established risk policy. Luminant has a disciplinary program to address any violations of the risk management policies and periodically reviews these policies to ensure they are responsive to changing market and business conditions.
TXU Energy— TXU Energy serves approximately 2.1 million residential and commercial retail electricity customers in Texas with approximately 61% of retail revenues in 2009 from residential customers. Texas is one of the fastest growing states in the nation with a diverse economy and, as a result, has attracted a number of competitors into the retail electricity market; consequently, competition is expected to continue to be robust. TXU Energy, as an active participant in this competitive market, provides retail electric service to all areas of the ERCOT market now open to competition, including the Dallas/Fort Worth, Houston, Corpus Christi, and lower Rio Grande Valley areas of Texas. TXU Energy continues to market its services in Texas to add new customers and to retain its existing customers. There are more than 140 active REPs certified to compete within the State of Texas.
TXU Energy’s strategy focuses on providing its customers with high quality customer service and creating new products and services to meet customer needs; accordingly, a new customer management computer system was implemented in 2009, and other customer care enhancements are being implemented to further improve customer satisfaction. TXU Energy offers a wide range of residential products to meet various customer needs. TXU Energy is investing $100 million over five years ending in 2012, including a total of $20 million spent as of December 31, 2009, in energy efficiency initiatives as part of a program to offer customers a broad set of innovative energy products and services.
Regulation —Luminant is an exempt wholesale generator under the Energy Policy Act of 2005 and is subject to the jurisdiction of the NRC with respect to its nuclear generation plant. NRC regulations govern the granting of licenses for the construction and operation of nuclear-fueled generation facilities and subject such facilities to continuing review and regulation. Luminant also holds a power marketer license from the FERC and, with respect to any wholesale power sales outside the ERCOT market, is subject to market behavior and any other competition-related rules and regulations under the Federal Power Act that are administered by the FERC.
Luminant is also subject to the jurisdiction of the PUCT’s oversight of the competitive ERCOT wholesale electricity market. PUCT rules do not set wholesale power prices in the market but do provide certain limits and framework for such pricing and market behavior.
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.
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Regulated Delivery Segment
The Regulated Delivery segment consists of the operations of Oncor. Oncor is a regulated electricity transmission and distribution company that provides the service of delivering electricity safely, reliably and economically to end-use consumers through its distribution systems, as well as providing transmission grid connections to merchant generation facilities and interconnections to other transmission grids in Texas. Oncor’s service territory has an estimated population in excess of seven million, about one-third of the population of Texas, and comprises 91 counties and over 400 incorporated municipalities, including Dallas/Fort Worth and surrounding suburbs, as well as Waco, Wichita Falls, Odessa, Midland, Tyler and Killeen. Oncor’s transmission and distribution assets are located principally in the north-central, eastern and western parts of Texas. Most of Oncor’s power lines have been constructed over lands of others pursuant to easements or along public highways, streets and rights-of-way as permitted by law. Oncor’s transmission and distribution rates are regulated by the PUCT.
Oncor is not a seller of electricity, nor does it purchase electricity for resale. It provides transmission services to other electricity distribution companies, cooperatives and municipalities. It provides distribution services to REPs, which sell electricity to retail customers.
Performance — Oncor achieved market-leading electricity delivery performance in nine out of 12 key PUCT market metrics in 2009. These metrics measure the success of transmission and distribution companies in facilitating customer transactions in the competitive Texas electricity market. Two additional metrics for expedited switching have been added by the PUCT in 2010.
Investing in Infrastructure and Technology —In 2009, Oncor invested $1.0 billion in its network to construct, rebuild and upgrade transmission lines and associated facilities, to extend the distribution infrastructure, and to pursue certain initiatives in infrastructure maintenance and information technology. Reflecting its commitment to infrastructure, in September 2008, Oncor and several other ERCOT utilities filed with the PUCT a plan to participate in the construction of transmission improvements designed to interconnect existing and future renewable energy facilities to transmit electricity from Competitive Renewable Energy Zones (CREZs) identified by the PUCT. In 2009, the PUCT awarded approximately $1.3 billion of CREZ construction projects to Oncor. The projects involve the construction of transmission lines to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of the state. The cost estimates for the CREZ construction projects are based upon analyses prepared by ERCOT in April 2008. In 2009, Oncor’s CREZ-related capital expenditures totaled $114 million. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulation and Rates.”
Oncor’s technology upgrade initiatives include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs. Oncor’s plans provide for the full deployment of over three million advanced meters by the end of 2012 to all residential and most non-residential retail electricity customers in Oncor’s service area. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount of electricity they are consuming and adjust their electricity consumption habits. As of December 31, 2009, Oncor has installed approximately 660 thousand advanced digital meters. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for Texas market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. In addition to the potential energy efficiencies from advanced metering, Oncor expects to invest over $300 million ($100 million in excess of regulatory requirements) over the five years ending in 2012 in programs designed to improve customer electricity demand efficiencies. As of December 31, 2009, Oncor has invested $125 million in these programs, including $67 million in 2009, and 22% of the amount in excess of regulatory requirements has been spent.
In a stipulation with several parties that was approved by the PUCT (as discussed in Note 6 to Financial Statements), Oncor committed to a variety of actions, including minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. Approximately 50% of this total was spent as of December 31, 2009. This spending does not include the CREZ facilities.
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Electricity Transmission—Oncor’s electricity transmission business is responsible for the safe and reliable operations of its transmission network and substations. These responsibilities consist of the construction and maintenance of transmission facilities and substations and the monitoring, controlling and dispatching of high-voltage electricity over Oncor’s transmission facilities in coordination with ERCOT.
Oncor is a member of ERCOT, and its transmission business actively assists the operations of ERCOT and market participants. Through its transmission business, Oncor participates with ERCOT and other member utilities to plan, design, construct and operate new transmission lines, with regulatory approval, necessary to maintain reliability, interconnect to merchant generation facilities, increase bulk power transfer capability and minimize limitations and constraints on the ERCOT transmission grid.
Transmission revenues are provided under tariffs approved by either the PUCT or, to a small degree related to an interconnection to other markets, the FERC. Network transmission revenues compensate Oncor for delivery of electricity over transmission facilities operating at 60 kV and above. Other services offered by Oncor through its transmission business include, but are not limited to: system impact studies, facilities studies, transformation service and maintenance of transformer equipment, substations and transmission lines owned by other parties.
Provisions of the 1999 Restructuring Legislation allow Oncor to annually update its transmission rates to reflect changes in invested capital. These “capital tracker” provisions encourage investment in the transmission system to help ensure reliability and efficiency by allowing for timely recovery of and return on new transmission investments.
At December 31, 2009, Oncor’s transmission facilities includes approximately 5,173 circuit miles of 345-kV transmission lines and approximately 9,954 circuit miles of 138-and 69-kV transmission lines. Sixty-two generation facilities totaling 36,165 MW are directly connected to Oncor’s transmission system, and 277 transmission stations and 702 distribution substations are served from Oncor’s transmission system.
At December 31, 2009, Oncor’s transmission facilities have the following connections to other transmission grids in Texas:
| Number of Interconnected Lines | ||||||
Grid Connections | 345kV | 138kV | 69kV | |||
Centerpoint Energy Inc. | 8 | — | — | |||
American Electric Power Company, Inc (a) | 4 | 7 | 12 | |||
Lower Colorado River Authority | 6 | 20 | 3 | |||
Texas Municipal Power Agency | 8 | 6 | — | |||
Texas New Mexico Power | 2 | 9 | 11 | |||
Brazos Electric Power Cooperative | 4 | 104 | 20 | |||
Rayburn Country Electric Cooperative | — | 32 | 7 | |||
City of Georgetown | — | 2 | — | |||
Tex-La Electric Cooperative | — | 11 | 1 | |||
Other small systems operating wholly within Texas | — | 3 | 2 | |||
(a) One of the 345-kV lines is an asynchronous high-voltage direct current connection with the Southwest Power Pool. | ||||||
Electricity Distribution— Oncor’s electricity distribution business is responsible for the overall safe and efficient operation of distribution facilities, including electricity delivery, power quality and system reliability. These responsibilities consist of the ownership, management, construction, maintenance and operation of the distribution system within Oncor’s certificated service area. Oncor’s distribution system receives electricity from the transmission system through substations and distributes electricity to end-users and wholesale customers through approximately 3,097 distribution feeders.
The Oncor distribution system includes over 3.1 million points of delivery. Over the past five years, the number of distribution system points of delivery served by Oncor, excluding lighting sites, grew an average of approximately 1.26% per year, adding approximately 24,689 points of delivery in 2009.
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The Oncor distribution system consists of approximately 56,260 miles of overhead primary conductors, approximately 21,587 miles of overhead secondary and street light conductors, approximately 15,352 miles of underground primary conductors and approximately 9,528 miles of underground secondary and street light conductors. The majority of the distribution system operates at 25-kV and 12.5-kV.
Oncor’s distribution rates for residential and small commercial users are based on actual monthly consumption (kWh), and rates for large commercial and industrial users are based on the greater of actual monthly demand (kilowatt) or 80% of peak monthly demand during the prior eleven months.
Customers —Oncor’s transmission customers consist of municipalities, electric cooperatives and other distribution companies. Oncor’s distribution customers consist of more than 70 REPs in Oncor’s certificated service area, including TCEH. Distribution revenues from TCEH represented 38% of Oncor’s total revenues for 2009, and revenues from subsidiaries of Reliant Energy, Inc., each of which is a non-affiliated REP, represented 14% of Oncor’s total revenues for 2009. No other customer represented more than 10% of Oncor’s total operating revenues. The consumers of the electricity delivered by Oncor are free to choose their electricity supplier from REPs who compete for their business.
Regulation and Rates —As its operations are wholly within Texas, Oncor is not a public utility as defined in the Federal Power Act and, as a result, it is not subject to general regulation under this Act.
The PUCT has original jurisdiction over transmission and distribution rates and services in unincorporated areas and in those municipalities that have ceded original jurisdiction to the PUCT and has exclusive appellate jurisdiction to review the rate and service orders and ordinances of municipalities. Generally, PURA prohibits the collection of any rates or charges by a public utility (as defined by PURA) that does not have the prior approval of the appropriate regulatory authority (PUCT or municipality with original jurisdiction). In accordance with a stipulation approved by the PUCT, Oncor filed a rate case with the PUCT in June 2008, based on a test year ended December 31, 2007. In August 2009, the PUCT issued a final order with respect to the rate review as discussed in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulation and Rates.”
At the state level, PURA, as amended, requires owners or operators of transmission facilities to provide open-access wholesale transmission services to third parties at rates and terms that are nondiscriminatory and comparable to the rates and terms of the utility’s own use of its system. The PUCT has adopted rules implementing the state open-access requirements for utilities that are subject to the PUCT’s jurisdiction over transmission services, such as Oncor.
Securitization Bonds—The Regulated Delivery segment includes Oncor’s wholly-owned, bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC. This financing subsidiary was organized for the limited purpose of issuing specified transition bonds in 2003 and 2004. Oncor Electric Delivery Transition Bond Company LLC issued $1.3 billion principal amount of securitization (transition) bonds to recover generation-related regulatory asset stranded costs and other qualified costs under an order issued by the PUCT in 2002.
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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 2008, we estimate that our generation plants produced 55 million short tons of CO2 based on continuously monitored data reported to and approved by the EPA. The two new lignite-fueled units that achieved substantial completion (as defined in the EPC Agreement for the units) in fall of 2009 and the one new lignite-fueled unit that is expected to achieve substantial completion (as defined in the EPC Agreement for the unit) in mid-2010 will generate additional CO2 emissions. Other aspects of our operations result in emissions of GHGs including, among other things, coal piles at our generation plants, sulfur hexafluoride in our electric operations, refrigerant from our chilling and cooling equipment, fossil fuel combustion in our motor vehicles and electricity usage at our facilities and headquarters. Because a substantial portion of our generation portfolio consists of lignite/coal-fueled generation plants, including the three new lignite-fueled generation units that are at or near completion, 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 a cap on carbon emissions with emitters allowed to trade unused emission allowances (cap-and-trade), a tax on carbon emissions (carbon tax) and incentives for the development of low-carbon technology. In addition to potential federal legislation to regulate GHG emissions, the US Congress might also consider other legislation that could result in the reduction of GHG emissions, such as the establishment of renewable energy portfolio standards.
Through our own evaluation and working in tandem with other companies and industry trade associations, we have supported the development of an integrated package of recommendations for the federal government to address the global climate change issue through federal legislation, including GHG emissions reduction targets for total 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 contend that any mechanism for allocation of GHG emission allowances should include substantial allocation of allowances to offset the cost of GHG regulation, including the cost to electricity consumers. In addition, we participate in a voluntary electric utility industry sector climate change initiative in partnership with the DOE. Our strategies are generally consistent with the “EEI Global Climate Change Points of Agreement” published by the Edison Electric Institute in January 2009 and “The Carbon Principles” announced in February 2008 by three major financial institutions. Finally, we have created a Sustainable Energy Advisory Board that advises us on technology development opportunities that reduce the effects of our operations on the environment while balancing the need to address the energy requirements of Texas. Our Sustainable Energy Advisory Board is comprised of individuals who represent the following interests, among others: the environment, customers, economic development in Texas and technology/reliability standards. If, despite these efforts, a substantial number of our investors, customers or others refuse to do business with us because of our GHG emissions, it could have a material adverse effect on our results of operations, financial position and liquidity.
Federal Level —A number of pieces of legislation dealing with GHG emissions have been proposed in the US Congress, including the Waxman-Markey bill, known as the American Clean Energy and Security Act of 2009 (Waxman-Markey) and the Kerry-Boxer bill, known as the Clean Energy Jobs and American Power Act (Kerry-Boxer). This proposed legislation is not law, but in June 2009 Waxman-Markey was passed by the US House of Representatives and sent to the US Senate for consideration. Kerry-Boxer recently was reported out of the US Senate Environment and Public Works Committee. President Obama has also expressed support for Waxman-Markey and Kerry-Boxer.
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As currently proposed, Waxman-Markey takes several approaches to address GHG emissions, including establishing renewable energy and energy efficiency standards, establishing performance standards for coal-fueled electricity generation units, and creating an economy-wide cap-and-trade program. The renewable energy and energy efficiency standards would require retail electricity suppliers to meet 6% of their load with renewable energy sources by 2012, increasing to 20% of their load by 2020, some of which could be met by energy efficiency measures. The performance standards for coal-fueled electricity generation units would require a 65% reduction in CO2 emissions for subject generation units initially permitted after January 1, 2020, and a 50% reduction in CO2 emissions for subject electricity generation units initially permitted between January 1, 2009 and January 1, 2020 once certain technology deployment criteria are met but no later than January 1, 2025. The cap-and-trade program would require emissions from capped sources, including coal-fueled electricity generation units, to be reduced 3% below 2005 levels by 2012, 17% by 2020, 42% by 2030 and 83% by 2050. The version of Waxman-Markey passed by the US House of Representatives included provisions that allocated a large percentage of the emissions allowances at no charge to various groups that would be impacted by such a cap-and-trade program, including certain merchant coal-fueled generation units. The Kerry-Boxer proposal employs a cap and trade approach similar to Waxman-Markey, but requires a 20% reduction in CO2 emissions levels by 2020 and provides a smaller grant of emission allowances to the electric power sector, including merchant coal-fueled generation units. Kerry-Boxer does not include a renewable energy and energy efficiency standard, which is addressed in a separate proposal in the US Senate.
Both Waxman-Markey and Kerry-Boxer remain subject to deliberation and modifications in the US Congress, thereby precluding an accurate estimate of the cost of compliance; however, if Waxman-Markey, Kerry-Boxer or similar legislation were to be adopted, our costs of compliance with the law could be material.
In April 2007, the US Supreme Court issued a decision in the case ofMassachusetts v. US Environmental Protection Agency holding that CO2 and other GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the federal Clean Air Act. The case was remanded to the EPA for further rulemaking to determine whether GHG emissions may reasonably be anticipated to endanger public health or welfare, or in the alternative, provide a reasonable explanation why GHG emissions should not be regulated. 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 will require it to begin regulating GHG emissions from motor vehicles and ultimately stationary sources under existing provisions of the federal Clean Air Act, and the EPA has already begun work on such regulations. Since the issuance of the finding, a number of parties (including the State of Texas) have appealed the finding to the US District Court of Appeals.
In September 2009, the EPA proposed two sets of regulations in anticipation of finalizing its endangerment finding: one to reduce GHG emissions from certain new motor vehicles and the other to establish new thresholds of GHG emissions for the applicability of permits under the Clean Air Act to stationary sources (known as the “tailoring rule”), including power generation facilities. The motor vehicle rules may be adopted as early as March 2010. Upon adoption of those regulations, GHG emissions, for the first time, will be air contaminants regulated under the Clean Air Act. The EPA asserts that once GHG emissions are air contaminants regulated under the Clean Air Act, major sources of GHG emissions - including fossil-fuel fired electricity generating units - will need to address GHG emissions in air permits for new sources and renewed permits for existing sources and to satisfy the control technology requirements of the Clean Air Act’s New Source Review (NSR) program with respect to GHG emissions if they undergo a major modification that is subject to the NSR program. The EPA solicited public comments on its position, originally set forth in a memorandum issued in December 2008 by then EPA Administrator Stephen Johnson, that CO2 and other GHGs are regulated air contaminants for purposes of the NSR program applicable to stationary sources, when they are controlled by a regulation under the Clean Air Act, and is expected to clarify the issue early in 2010. The EPA’s proposed tailoring rule seeks to define the threshold of GHG emissions for determining applicability of the Clean Air Act’s permitting programs and NSR program at levels greater than the lower emission thresholds contained in the Clean Air Act. In addition, in September 2009, the EPA issued a final rule requiring the reporting, by March 2011, of calendar year 2010 GHG emissions from specified large GHG emissions sources in the US (such reporting rule would apply to our lignite-fueled generation facilities).
As with the regional GHG regulatory programs, any federal GHG legislation is expected to limit, to some extent, the EPA’s authority to regulate GHGs under existing Clean Air Act regulatory programs, but if Congress fails to pass GHG legislation, the EPA is expected to continue its announced Clean Air Act regulatory actions. Our costs of complying with future EPA limitations on GHG emissions could be material.
In September 2009, the 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, and is still subject to appeal.
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In October 2009, the US Court of Appeals for the Fifth Circuit issued a decision in the case ofComer v. Murphy Oil USA holding that certain Mississippi residents have standing to sue to pursue state law nuisance, negligence and trespass claims for injuries purportedly suffered because the defendants’ emissions of GHGs allegedly increased the destructive force of Hurricane Katrina. This decision, like theAmerican Electric Power decision discussed above, does not address the merits of such a nuisance claim and is still subject to appeal.
In September 2009, the 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 nonjudiciable political questions and because plaintiffs lacked standing to sue. The decision is subject to appeal.
While we are not a party to these suits, they could encourage or form the basis for a lawsuit asserting similar nuisance claims regarding emissions of GHGs. If any similar suit was successfully asserted against us in the future, it could have a material adverse effect on our business, results of operations and financial condition.
State and Regional Level —There are currently no Texas state regulations in effect concerning GHGs, and there are no regional initiatives concerning GHGs in which the State of Texas is a participant. We oppose state-by-state regulation of GHGs. In October 2009, Public Citizen Inc. filed a lawsuit against the Texas Commission on Environmental Quality (TCEQ) and its commissioners seeking to compel the TCEQ to regulate GHG emissions under the Texas Clean Air Act. The Attorney General of Texas has filed special exceptions to the Public Citizen pleading. We are not a party to this litigation. If limitations on emissions of GHGs are enacted in Texas, our costs of compliance could be material.
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 the proposals described above are in their formative stages, we are unable to predict the potential effects on our business, financial condition and/or results of operations; however, any such effects could be material. The effect will depend, in large part, on the specific requirements of the legislation or regulation and how much, if any, of the costs are included in wholesale prices.
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EFH Corp.’s Voluntary Energy Efficiency, Renewable Energy, and Global Climate Change Efforts — We are considering, or expect to be actively engaged in, business activities that could result in reduced GHG emissions including:
| • | Investing in Energy Efficiency or Related Initiatives by Our Competitive Businesses — Our competitive businesses expect to invest $100 million in energy efficiency or related initiatives over a five-year period that began in 2008, including initiatives such as the TXU Energy Power Monitor™, an in-home display device that enables residential customers to monitor whole-house energy usage and cost in real-time, and projects month-end bill amounts; the TXU Energy iThermostat™, a web-enabled programmable thermostat with a load control feature for cycling off air conditioners during times of peak energy demand; time-based electricity rates that are expected to work in conjunction with advanced metering infrastructure; rate plans that include electricity from renewable resources; an Online Energy Store that provides customers the opportunity to purchase hard-to-find, cost-effective energy efficiency products; a Compact Fluorescent Light (CFL) program that provides packages of CFLs to customers; a program to refer customers to energy efficiency contractors; the provision of rebates to business customers for purchasing new energy efficient equipment for their facilities based on a detailed engineering design through the Energy Conservation Investment Program; the Energy Efficiency Assistance Program that delivers products and services, as well as grants through social service agencies, to improve the energy efficiency of participating low income customer homes and apartment complexes; and online energy audit tools and tips for using less electricity; |
| • | Investing in Energy Efficiency Initiatives by Oncor — In addition to the potential energy efficiencies from advanced metering, Oncor expects to invest over $300 million in energy efficiency initiatives over a five-year period that began in 2008 through such efforts as traveling across the State of Texas educating consumers about electricity, including the benefits of energy efficiency, advanced meters and renewable energy, and investment of over $16 million in the installation of solar photovoltaic systems in customer’s homes and facilities that is expected to result in savings of up to 4.8 million kWh of electricity; |
| • | Participating in the CREZ Program — Oncor has been selected by the PUCT to construct approximately $1.3 billion of CREZ transmission facilities that are designed to connect existing and future renewable energy facilities to the electricity transmission system in ERCOT; |
| • | Purchasing Electricity from Renewable Sources — We expect to remain a leader in the ERCOT market in providing electricity from renewable sources by purchasing up to 1,500 MW of wind power. Our total wind power portfolio is currently more than 900 MW; |
| • | Promoting the Use of Solar Power — TXU Energy currently purchases surplus renewable distributed generation from qualified customers. In addition, TXU Energy’s Solar Academy works with Texas school districts to teach and demonstrate the benefits of solar power; |
| • | Investing in Technology — We continue to evaluate the development and commercialization of cleaner power facility technologies; technologies that support sequestration and/or reduction of CO2; incremental renewable sources of electricity, including wind and solar power; energy storage, including advanced battery and compressed air storage, as well as related technologies that seek to lower emissions intensity. Additionally, we continue to explore the advances in electric cars and plug-in hybrid electric vehicles that have the potential to reduce overall GHG emissions; |
| • | Evaluating the Development of a New Nuclear Generation Facility — We have filed an application with the NRC for combined construction and operating licenses for up to 3,400 MW of new nuclear generation capacity (the lowest GHG emission source of baseload generation currently available) at our Comanche Peak nuclear generation facility. In addition, we have (i) filed a loan guarantee application with the DOE for financing of the proposed units and (ii) formed a joint venture with Mitsubishi Heavy Industries Ltd. (MHI) to further develop the units using MHI’s US-Advanced Pressurized Water Reactor technology, and |
| • | Offsetting GHG Emissions by Planting Trees —We are engaged in a number of tree planting programs that offset GHG emissions, resulting in the planting of over 1.1 million trees in 2009. The majority of these trees were planted as part of our mining reclamation efforts but also include TXU Energy’s Urban Tree Farm program, which has planted more than 150,000 trees since its inception in 2002. |
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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. Since the D.C. Circuit Court did not prescribe a deadline for this revision, at this time, we cannot predict how or when the EPA may revise CAIR. See Note 3 to Financial Statements for discussion of the impairment of emission allowances intangible assets.
In 2005, the EPA also published a final rule requiring reductions of mercury emissions from coal-fueled generation plants. The Clean Air Mercury Rule (CAMR) was based on a nationwide cap and trade approach. The mercury reductions were required to be phased in between 2010 and 2018. In March 2008, the D.C. Circuit Court vacated CAMR. In February 2009, the 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. See Item 3, “Legal Proceedings — Litigation Related to Generation Facilities.”
SO2 reductions required under the proposed regional haze/visibility rule (or so-called BART rule) only apply to units built between 1962 and 1977. The reductions are required on a unit-by-unit basis. The EPA provides the option for states to use CAIR to satisfy BART reductions for electricity generating units, and Texas has chosen this option. We believe the D.C. Circuit Court decision to leave CAIR in place while the EPA revises it should allow Texas to move forward with its plans.
In connection with our construction of three new lignite-fueled generation units in Texas, we have committed to reduce emissions of NOx, SO2 and mercury through the installation of emissions control equipment at both new and existing units and fuel blending at some existing units. We have also applied with the TCEQ to seek a “maximum achievable control technology” determination for our two Oak Grove units that are under construction and have agreed to offset any emissions above those levels. These efforts, which will involve incremental equipment investments as well as additional costs for facility operations and maintenance in the future, will be coordinated with efforts related to applicable environmental rules to provide the most cost-effective compliance plan options.
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The following are the major air quality improvements planned at our existing and new coal-fueled generation plants to help meet the offset and reduction commitment:
| • | To reduce NOx emissions, we have applied for permits to install selective catalytic reduction (SCR) systems at our Martin Lake plant. In addition, we have installed selective non-catalytic reduction systems at our Monticello and Big Brown plants and improved the low-NOx burner technology at one of our Monticello units. These activities are in addition to SCR systems being installed at the legacy Sandow unit and at the new Oak Grove units; |
| • | To reduce mercury emissions, we plan to use activated carbon injection, a sorbent injection system technology, at all of our plants, and |
| • | To reduce SO2 emissions, we plan to increase use of lower-sulfur coal at various plants. In addition, Martin Lake mine is using coal-cleaning technology to reduce both SO2 and mercury emissions, and we are evaluating the effectiveness of this technology at Big Brown and Monticello mines. |
The Clean Air Act requires each state to monitor air quality for compliance with federal health standards. The standards for ozone are not being achieved in several areas of Texas. The TCEQ adopted State Implementation Plan (SIP) rules in May 2007 to deal with eight-hour ozone standards, which required 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 facilities.
We believe that we hold all required emissions permits for facilities in operation and have applied for or obtained the necessary construction permits for facilities under construction.
Water
The TCEQ and the EPA have jurisdiction over water discharges (including storm water) from facilities in Texas. We believe our facilities are presently in material compliance with applicable state and federal requirements relating to discharge of pollutants into water. We believe we hold all required waste water discharge permits from the TCEQ for facilities in operation and have applied for or obtained necessary permits for facilities under construction. We also believe we can satisfy the requirements necessary to obtain any required permits or renewals. Recent changes to federal rules pertaining to the Spill Prevention, Control and Countermeasure (SPCC) plans for oil-filled electrical equipment and bulk storage facilities for oil will require updating of certain of our facilities. We have determined that SPCC plans will be required for certain substations, work centers and distribution systems by November 10, 2010, and we are currently compiling data for development of these plans.
Diversion, impoundment and withdrawal of water for cooling and other purposes are subject to the jurisdiction of the TCEQ and the EPA. We believe we possess all necessary permits for these activities from the TCEQ for our present operations. We have obtained the necessary water rights permit from the TCEQ for the lignite mine that supports the Oak Grove units. Clean Water Act Section 316(b) regulations pertaining to existing water intake structures at large generation facilities were published by the EPA in 2004. As prescribed in the regulations, we began implementing a monitoring program to determine the future actions that might need to be taken to comply with these regulations. In January 2007, a federal court ruled against the EPA in a lawsuit brought by environmental groups challenging aspects of these regulations, and in July 2007, the EPA announced that it was suspending the regulations pending further rulemaking. The 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). We cannot predict the impact on our operations of the suspended regulations or of new regulations, if any, that replace them.
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Radioactive Waste
We currently ship low-level waste material to a disposal facility outside of Texas. Under the federal Low-Level Radioactive Waste Policy Act of 1980, as amended, the State of Texas is required to provide, either on its own or jointly with other states in a compact, for the disposal of all low-level radioactive waste generated within the state. The State of Texas has agreed to a compact for a disposal facility that would be located in Texas. That compact was ratified by Congress and signed by the President in 1998. In 2003, the State of Texas enacted legislation allowing a private entity to be licensed to accept low-level radioactive waste for disposal, and in 2004 the State received a license application from such an entity for review. In January 2009, the TCEQ approved this permit. We expect to continue to ship low-level waste material off-site for as long as an alternative disposal site is available. Should existing off-site disposal become unavailable, the low-level waste material will be stored on-site. (See discussion under “Luminant — Nuclear Generation Operations” above.)
We believe that our on-site used nuclear fuel storage capability is sufficient for a minimum of three years. The nuclear industry is continuing to review ways to enhance security of used-fuel storage with the NRC to fully utilize physical storage capacity. Current on-site used nuclear fuel storage capability will require the use of the industry technique of dry cask storage within the next three years.
Solid Waste, Including Fly Ash Associated with Lignite/Coal-Fueled Generation
Treatment, storage and disposal of solid waste and hazardous waste are regulated at the state level under the Texas Solid Waste Disposal Act and at the federal level under the Resource Conservation and Recovery Act of 1976, as amended, and the Toxic Substances Control Act. The EPA has issued regulations under the Resource Conservation and Recovery Act of 1976 and the Toxic Substances Control Act, and the TCEQ has issued regulations under the Texas Solid Waste Disposal Act applicable to our facilities. We believe we are in material compliance with all applicable solid waste rules and regulations. In addition, we have registered solid waste disposal sites and have obtained or applied for permits required by such regulations.
In December 2008, an ash impoundment facility at a Tennessee Valley Authority (TVA) site ruptured releasing a significant quantity of coal ash slurry. No impoundment failures of this magnitude have ever occurred at any of our impoundments, which are inspected on a regular basis, and we routinely sample groundwater monitoring wells to ensure compliance with all applicable regulations. As a result of the TVA ash impoundment failure, the EPA announced that it intends to develop regulations governing the management of coal combustion residuals. We are unable to predict future impacts on our financial condition or operations due to any legislative or regulatory actions that may be taken in response to the TVA impoundment failure.
The EPA issued a notice in December 2009 that it had identified several industries, including the electric power industry, that should be subject to financial responsibility requirements under the Comprehensive Environmental Response, Compensation and Liability Act consistent with the risk associated with their production, transportation, treatment, storage or disposal of hazardous substances. The EPA indicated in its notice that it would develop regulations that define the scope of those financial responsibility requirements. We do not know, at this time, the scope of these requirements, nor are we able to estimate the potential cost (which could be material) of complying with any such new requirements.
Environmental Capital Expenditures
Capital expenditures for our environmental projects totaled $149 million in 2009 and are expected to total approximately $80 million in 2010, consisting primarily of environmental projects at existing lignite/coal-fueled generation plants. These amounts are exclusive of emissions control equipment investment planned as part of the three-unit generation development program, which is expected to total up to $500 million over the construction period. See discussion above under “Luminant — Lignite/Coal-Fueled Generation Operations” regarding planned investments in emissions control systems.
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| 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 Relating to Substantial Indebtedness and Debt Agreements
Our substantial leverage could adversely affect our ability to raise additional capital to fund our operations, limit our ability to react to changes in the economy or our industry, expose us to interest rate risk to the extent of our variable rate debt and prevent us from meeting obligations under the various debt agreements governing our indebtedness.
We are highly leveraged. As of December 31, 2009, our consolidated principal amount of debt (short term borrowings and long-term debt, including amounts due currently) totaled $44.191 billion (see Note 12 to Financial Statements). Our substantial leverage could have important consequences, including:
| • | making it more difficult for us to make payments on our indebtedness; |
| • | requiring a substantial portion of cash flow from operations to be dedicated to the payment of principal and interest on indebtedness, therefore reducing our ability to use our cash flow to fund operations, capital expenditures and future business opportunities and execute our strategy; |
| • | increasing our vulnerability to adverse economic, industry or competitive developments; |
| • | exposing us to the risk of increased interest rates because, as of December 31, 2009, taking into consideration interest swap transactions, 10% 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; |
| • | limiting our ability to adjust to changing market conditions, and |
| • | placing us at a competitive disadvantage compared to competitors who are less highly leveraged and who therefore, may be able to take advantage of opportunities that we cannot due to our substantial leverage. |
A substantial amount of this indebtedness is comprised of our indebtedness under the TCEH Senior Secured Facilities, substantially all of which matures in October 2014. We may not be able to refinance the TCEH Senior Secured Facilities or our other existing indebtedness because of our high levels of debt and debt incurrence restrictions under our debt agreements or because of generally adverse conditions in credit markets.
Despite our current high indebtedness level, we may still be able to incur substantially more indebtedness. This could further exacerbate the risks associated with our substantial indebtedness.
We may be able to incur additional indebtedness in the future. Although our debt agreements contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of significant qualifications and exceptions, and under certain circumstances, the amount of indebtedness, including secured indebtedness, that could be incurred in compliance with these restrictions could be substantial. If new debt is added to our existing debt levels, the related risks that we now face would intensify.
Increases in interest rates may negatively impact our operating results and financial condition.
Certain of our borrowings are at variable rates of interest. To the extent the interest rate for such borrowings is not fixed by interest rate swaps, an increase in interest rates would have a negative impact on our results of operations by causing an increase in interest expense.
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At December 31, 2009, we had $4.221 billion aggregate principal amount of variable rate long-term indebtedness (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 $16.30 billion in notional amount of variable rate indebtedness. As a result, as of December 31, 2009, a 100 basis point increase in interest rates would increase our annual interest expense by approximately $42 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.”
Interest expense and related charges for the year ended December 31, 2009 was $2.912 billion.
EFH Corp.’s and its subsidiaries’ debt agreements contain restrictions that limit flexibility in operating our businesses.
EFH Corp.’s and its subsidiaries’ debt agreements contain various covenants and other restrictions that limit the ability of EFH Corp. and/or its restricted subsidiaries to engage in specified types of transactions and may adversely affect our ability to operate our businesses. These covenants and other restrictions limit EFH Corp.’s and/or its restricted subsidiaries’ ability to, among other things:
| • | incur additional indebtedness or issue preferred shares; |
| • | pay dividends on, repurchase or make distributions in respect of capital stock or make other restricted payments; |
| • | make investments; |
| • | sell or transfer assets; |
| • | create liens; |
| • | consolidate, merge, sell or otherwise dispose of all or substantially all of its or their assets; |
| • | enter into transactions with its or their affiliates, and |
| • | repay, repurchase or modify certain subordinated and other material debt. |
There are a number of important limitations and exceptions to these covenants and other restrictions. See Note 12 to Financial Statements for a description of these covenants and other restrictions.
Under the TCEH Senior Secured Facilities, TCEH is required to maintain a leverage ratio below specified levels. TCEH’s ability to maintain its leverage ratio below such levels can be affected by events beyond its control, and there can be no assurance that it will meet any such ratio.
A breach of any of these covenants or restrictions could result in an event of default under one or more of EFH Corp.’s and its subsidiaries’ debt agreements, including as a result of cross default provisions. Upon the occurrence of an event of default under one of the debt agreements, the lenders could elect to declare all amounts outstanding under that debt agreement to be immediately due and payable and/or terminate all commitments to extend further credit. Such actions by those lenders could cause cross defaults under EFH Corp.’s and its subsidiaries’ other indebtedness. If EFH Corp. or one of its subsidiaries was unable to repay those amounts, the lenders could proceed against any collateral granted to them to secure such indebtedness. If lenders accelerate the repayment of borrowings, EFH Corp. or such subsidiary 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, its immediate parent, Oncor Holdings, and Oncor Holdings’ other subsidiaries. Those measures include, among other things:
| • | Oncor being treated as an unrestricted subsidiary with respect to EFH Corp.’s indebtedness; |
| • | Oncor not being restricted from incurring its own indebtedness; |
| • | Oncor not guaranteeing or pledging any of its assets to secure the indebtedness of any member of the Texas Holdings Group, and |
| • | restrictions on dividends, and the right of the independent members of Oncor’s board of directors and the primary noncontrolling member of Oncor to block the payment of dividends. |
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We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our debt agreements, which may not be successful.
Our ability to make scheduled payments on or to refinance debt obligations depends on our financial condition and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
If cash flows and capital resources are insufficient to fund EFH Corp.’s and its subsidiaries’ debt service obligations, we or our subsidiaries could face substantial liquidity problems and might be forced to reduce or delay investments and capital expenditures, or to dispose of assets or operations, seek additional capital or restructure or refinance indebtedness. These alternative measures may be costly or may not be successful or adequate for us and our subsidiaries to meet our debt service obligations. Additionally, EFH Corp.’s and its subsidiaries’ 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.
Under the terms of TCEH’s debt agreements, TCEH is restricted from making certain payments to EFH Corp.
EFH Corp. is a holding company and substantially all of its consolidated assets are held by its subsidiaries. As of December 31, 2009, TCEH and its subsidiaries held approximately 70% of EFH Corp.’s consolidated assets and for the year ended December 31, 2009, TCEH and its subsidiaries represented approximately 83% of EFH Corp.’s consolidated revenues. Accordingly, EFH Corp. depends upon TCEH for a significant amount of its cash flows and ability to pay its obligations. However, under the terms of TCEH’s debt agreements, TCEH is restricted from making certain payments, including dividends and loans, 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, TCEH’s debt agreements do not permit such intercompany loans to service EFH Corp. debt unless required for EFH Corp. to pay principal, premium and interest when due on indebtedness incurred by EFH Corp. to finance the Merger, indebtedness in existence prior to the Merger, or any indebtedness incurred by EFH Corp. to replace, refund or refinance such debt. Such loans are also permitted to service other debt, subject to limitations on the amount of the loans. As a result, unless and until the net proceeds from any new debt issuance 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 debt will be limited. In addition, TCEH is prohibited from making some loans to EFH Corp. if certain events of default under TCEH’s debt agreements have occurred and are continuing.
Under the terms of the indentures governing the EFIH Notes, Intermediate Holding 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, 2009, Intermediate Holding and its subsidiaries held approximately 27% of EFH Corp.’s consolidated assets and for the year ended December 31, 2009, Intermediate Holding and its subsidiaries represented approximately 17% of EFH Corp.’s consolidated revenues. Accordingly, EFH Corp. depends upon Intermediate Holding for a significant amount of its cash flows and ability to pay its obligations. However, under the terms of the indenture governing the EFIH Notes, Intermediate Holding is restricted from making certain payments, including dividends and loans, to EFH Corp., except in limited circumstances.
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EFH Corp. has a very limited ability to control activities at Oncor due to structural and operational “ring-fencing” measures.
EFH Corp. depends upon Oncor for a significant amount of its cash flows and ability to pay its obligations. However, EFH Corp. has a very limited ability to control the activities of Oncor. As part of the “ring-fencing” measures implemented by EFH Corp. and Oncor, a majority of the members of Oncor’s board of directors are required to meet the New York Stock Exchange requirements for independence in all material respects, and the unanimous consent of such directors is required for Oncor to take certain actions. In addition, any new independent directors are required to be appointed by the nominating committee of Oncor Holdings’ board of directors, a majority of whose members are independent directors. No member of EFH Corp.’s management is a member of Oncor’s board of directors. Under Oncor Holdings’ and Oncor’s organizational documents, EFH Corp. has the right, indirectly, to consent to new issuances of equity securities by Oncor, material transactions with third parties involving Oncor outside of the ordinary course of business, actions that cause Oncor’s assets to increase the level of jurisdiction of the FERC, any changes to the state of formation of Oncor, material changes to accounting methods not required by 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.
Risks Relating 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.
Because EFH Corp. is a holding company, its obligations to its creditors are structurally subordinated to all existing and future liabilities and existing and future preferred stock of its subsidiaries that do not guarantee such obligations. Therefore, with respect to subsidiaries that do not guarantee EFH Corp.’s obligations, EFH Corp.’s rights and the rights of its creditors to participate in the assets of any subsidiary in the event that such a subsidiary is liquidated or reorganized are subject to the prior claims of such subsidiary’s creditors and holders of such subsidiary’s preferred stock. To the extent that EFH Corp. may be a creditor with recognized claims against any such subsidiary, EFH Corp.’s claims would still be subject to the prior claims of such subsidiary’s creditors to the extent that they are secured or senior to those held by EFH Corp. Subject to restrictions contained in financing arrangements, EFH Corp.’s subsidiaries may incur additional indebtedness and other liabilities.
Oncor may or may not make any distributions to EFH Corp.
Upon the consummation of the Merger, EFH Corp. and Oncor implemented certain structural and operational “ring-fencing” measures based on principles articulated by rating agencies and commitments made by Texas Holdings and Oncor to the PUCT and the FERC to further enhance Oncor’s credit quality. These measures were put into place to mitigate Oncor’s credit exposure to the Texas Holdings Group and to reduce the risk that the assets and liabilities of Oncor would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities.
As part of the ring-fencing measures, a majority of the members of the board of directors of Oncor are required to be, and are, independent from EFH Corp. Any new independent directors of Oncor are required to be appointed by the nominating committee of Oncor Holdings. The organizational documents of Oncor give these independent directors, acting by majority vote, and, during certain periods, any director designated by Texas Transmission, the express right to prevent distributions from Oncor if they determine that it is in the best interests of Oncor to retain such amounts to meet expected future requirements. Accordingly, there can be no assurance that Oncor will make any distributions to EFH Corp.
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In addition, Oncor’s organizational documents limit Oncor’s distributions to EFH Corp. through December 31, 2012 to an amount not to exceed Oncor’s net income (determined in accordance with US GAAP, subject to certain defined adjustments, including goodwill impairments) and prohibit Oncor from making any distribution to EFH Corp. so long as and to the extent that such distribution would cause Oncor’s regulatory capital structure to exceed the debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.
In March 2009, the PUCT awarded Oncor the right to construct approximately $1.3 billion of transmission lines and facilities associated with its CREZ Transmission Plan (see discussion in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulation and Rates”). With the award, it is likely Oncor will incur additional debt. In addition, Oncor may incur additional debt in connection with other investments in infrastructure or technology. Accordingly, while Oncor is required to maintain a debt-to-equity ratio of 60% debt to 40% equity, there can be no assurance that Oncor’s equity balance will be sufficient to maintain the required debt-to-equity ratio established from time to time by the PUCT for ratemaking purposes, thereby restricting Oncor from making any distributions to EFH Corp.
Risks Relating 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 Electric Reliability Organization, the Texas Regional Entity, the RRC, the TCEQ, the FERC, the EPA and the NRC) and the rules, guidelines and protocols of ERCOT with respect to matters including, but not limited to, market structure and design, operation of nuclear generation facilities, construction and operation of other generation facilities, construction and operation of transmission facilities, acquisition, disposal, depreciation and amortization of regulated assets and facilities, recovery of costs and investments, decommissioning costs, return on invested capital for regulated businesses, market behavior rules, present or prospective wholesale and retail competition and environmental matters. TCEH, along with other market participants, is subject to electricity pricing constraints and market behavior and other competition-related rules and regulations under PURA that are administered by the PUCT and ERCOT, and, with respect to any wholesale power sales outside the ERCOT market, is subject to market behavior and other competition-related rules and regulations under the Federal Power Act that are administered by the FERC. Changes in, revisions to, or reinterpretations of existing laws and regulations (for example, with respect to prices at which TCEH may sell electricity, the required permits for the three lignite-fueled generation units recently completed or currently under construction or the cost of emitting greenhouse gases) may have an adverse effect on our businesses.
The Texas Legislature meets every two years, and from time to time bills are introduced and considered that could materially affect our businesses. There can be no assurance that future action of the Texas Legislature will not result in legislation that could have a material adverse effect on us and our financial prospects.
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PURA, the PUCT, ERCOT, the RRC 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 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 twenty-seven agencies scheduled for Sunset review by the Sunset Commission in 2009 and 2010, four hold primary interest for us: the PUCT, the OPC, the RRC and ERCOT, which are subject to a focused, limited scope, or special purpose review. These agencies, for the most part, govern and operate the electricity and mining markets in Texas upon which our business model is based. PURA, which expires September 1, 2011, is also subject to Sunset review. If the Texas Legislature fails to renew PURA or any of these agencies, it could result in a significant restructuring of the Texas electricity market or regulatory regime that could have a material impact on our business. There can be no assurance that future action of the Sunset Commission will not result in legislation that could have a material adverse effect on us and our financial prospects.
Litigation, legal proceedings, regulatory investigations or other administrative proceedings could expose us to significant liabilities and reputation damage, and have a material adverse effect on our results of operations, and the litigation environment in which we operate poses a significant risk to our businesses.
We are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, environmental and injuries and damages issues, among other matters. We evaluate litigation claims and legal proceedings to assess the likelihood of unfavorable outcomes and to estimate, if possible, the amount of potential losses. Based on these assessments and estimates, we establish reserves and disclose the relevant litigation claims or legal proceedings, as appropriate. These assessments and estimates are based on the information available to management at the time and involve a significant amount of judgment. Actual outcomes or losses may differ materially from current assessments and estimates. The settlement or resolution of such claims or proceedings may have a material adverse effect on our results of operations. In addition, judges and juries in the State of Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage and business tort cases. We use appropriate means to contest litigation threatened or filed against us, but the litigation environment in the State of Texas poses a significant business risk.
We are involved in the ordinary course of business in permit applications and renewals, and we are exposed to the risk that certain of our operating permits may not be granted or renewed on satisfactory terms. Failure to obtain and maintain the necessary permits to conduct our businesses could have a material adverse effect on our results of operations.
We are also involved in the ordinary course of business in regulatory investigations and other administrative proceedings, and we are exposed to the risk that we may become the subject of additional regulatory investigations or administrative proceedings. See 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.
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TXU Energy may lose a significant number of retail customers due to competitive marketing activity by other retail electric providers.
TXU Energy faces competition for customers. Competitors may offer lower prices and other incentives, which, despite TXU Energy’s long-standing relationship with customers, may attract customers away from TXU Energy.
In some retail electricity markets, TXU Energy’s principal competitor may be the incumbent REP. The incumbent REP has the advantage of long-standing relationships with its customers, including well-known brand recognition.
In addition to competition from the incumbent REP, TXU Energy may face competition from a number of other energy service providers, other energy industry participants, or nationally branded providers of consumer products and services who may develop businesses that will compete with TXU Energy. Some of these competitors or potential competitors may be larger or better capitalized than TXU Energy. If there is inadequate potential margin in these retail electricity markets, it may not be profitable for TXU Energy to compete in these markets.
TCEH’s revenues and results of operations may be negatively impacted by decreases in market prices for power, decreases in natural gas prices, and/or decreases in market heat rates.
TCEH (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 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; |
| • | transmission or transportation constraints, inoperability or inefficiencies; |
| • | availability of competitively-priced alternative energy sources; |
| • | changes in supply and demand for energy commodities, including nuclear fuel and related enrichment and conversion services; |
| • | changes in generation efficiency; |
| • | outages at our generation facilities or those of our competitors; |
| • | changes in the credit risk or payment practices of market participants; |
| • | changes in production and storage levels of natural gas, lignite, coal, crude oil, diesel and other refined products; |
| • | natural disasters, wars, sabotage, terrorist acts, embargoes and other catastrophic events, and |
| • | federal, state and local energy, environmental and other regulation and legislation. |
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All of our generation facilities are located in the ERCOT market, a market with limited interconnections to other markets. Wholesale electricity prices in the ERCOT market generally correlate with the price of natural gas because marginal electricity demand is generally supplied by natural gas-fueled generation facilities.
Wholesale electricity prices also correlate with market heat rates (a measure of efficiency of the marginal price-setting generator of electricity), which could fall if demand for electricity were to decrease or if additional generation facilities are built in ERCOT. Accordingly, the contribution to earnings and the value of our baseload (lignite/coal-fueled and nuclear) generation assets, which provided a substantial portion of our supply volumes in 2009, are dependent in significant part upon the price of natural gas and market heat rates. As a result, our baseload generation assets could significantly decrease in profitability and value if natural gas prices or market heat rates fall.
Our assets or positions cannot be fully hedged against changes in commodity prices and market heat rates, and hedging transactions may not work as planned or hedge counterparties may default on their obligations.
We cannot fully hedge the risk associated with changes in commodity prices, most notably natural gas prices, or market heat rates because of the expected useful life of our generation assets and the size of our position relative to market liquidity. To the extent we have unhedged positions, fluctuating commodity prices and/or market heat rates can materially impact our results of operations and financial position, either favorably or unfavorably.
To manage our financial exposure related to commodity price fluctuations, we routinely enter into contracts to hedge portions of purchase and sale commitments, fuel requirements and inventories of natural gas, lignite, coal, crude oil, diesel fuel and refined products, and other commodities, within established risk management guidelines. As part of this strategy, we routinely utilize fixed-price forward physical purchase and sale contracts, futures, financial swaps and option contracts traded in over-the-counter markets or on exchanges. Although we devote a considerable amount of time and effort to the establishment of risk management procedures, as well as the ongoing review of the implementation of these procedures, the procedures in place may not always function as planned and cannot eliminate all the risks associated with these activities. For example, we hedge the expected needs of our wholesale and retail customers, but unexpected changes due to weather, natural disasters, market constraints or other factors could cause us to purchase power to meet unexpected demand in periods of high wholesale market prices or resell excess power into the wholesale market in periods of low prices. As a result of these and other factors, we cannot precisely predict the impact that risk management decisions may have on our businesses, results of operations or financial position.
With the tightening of credit markets, there has been some decline in the number of market participants in the wholesale energy commodities markets, resulting in less liquidity, particularly in the ERCOT electricity market. Participation by financial institutions and other intermediaries (including investment banks) has particularly declined. Extended declines in market liquidity could materially affect our ability to hedge our financial exposure to desired levels.
To the extent we engage in hedging and risk management activities, we are exposed to the risk that counterparties that owe us money, energy or other commodities as a result of market transactions will not perform their obligations. Should the counterparties to these arrangements fail to perform, we might be forced to enter into alternative hedging arrangements or honor the underlying commitment at then-current market prices. In such event, we might incur losses in addition to amounts, if any, already paid to the counterparties. ERCOT market participants are also exposed to risks that another ERCOT market participant may default on its obligations to pay ERCOT for power taken, in which case such costs, to the extent not offset by posted security and other protections available to ERCOT, may be allocated to various non-defaulting ERCOT market participants, including us.
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Our use of assets as collateral for hedging arrangements could be materially impacted if certain proposed legislation regarding the regulation of over-the-counter financial derivatives were to be enacted and be applicable to us.
The Obama Administration has proposed financial market reforms with respect to the currently unregulated Over-the-Counter (OTC) financial derivatives market. As a result, the US House of Representatives has approved a bill to regulate OTC derivatives. The bill would require certain entities to clear OTC derivatives that are currently traded on the bilateral market through exchanges, which require that all collateral be in the form of cash. We have entered into a significant number of asset-backed OTC derivatives to hedge risks associated with commodity and interest rate exposure. The US House of Representatives legislation would not require us to clear our OTC derivatives through exchanges. However, other proposals would have required such clearing, and it is not evident what, if any, US Senate legislation might be approved. If we were required to clear such transactions, we would likely be precluded from using our noncash assets as collateral for hedging arrangements. This preclusion could have a material impact on our liquidity, particularly if the final legislation does not provide for the grandfathering of existing OTC derivatives. As a result, if applied to our OTC derivatives transactions, legislation that impairs the use of asset-backed transactions could significantly increase our costs of entering into OTC derivatives and/or could significantly limit our ability to enter into OTC derivatives and hedge our commodity and interest rate risks. We cannot predict whether or when final legislation will be enacted or whether the US House of Representatives bill exemptions will be included in any final legislation.
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 and financial condition.
The operation and maintenance of electricity generation and delivery facilities involves many risks, including, as applicable, start-up risks, breakdown or failure of facilities, lack of sufficient capital to maintain the facilities, the dependence on a specific fuel source or the impact of unusual or adverse weather conditions or other natural events, as well as the risk of performance below expected levels of output, efficiency or reliability, the occurrence of any of which could result in lost revenues and/or increased expenses. A significant number of our facilities were constructed many years ago. In particular, older generating equipment and transmission and distribution equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep operating at peak efficiency or reliability. The risk of increased maintenance and capital expenditures arises from (a) increased starting and stopping of generation equipment due to the volatility of the competitive generation market, (b) any unexpected failure to generate electricity, including failure caused by breakdown or forced outage and (c) damage to facilities due to storms, natural disasters, wars, terrorist acts and other catastrophic events. Further, our ability to successfully and timely complete capital improvements to existing facilities or other capital projects is contingent upon many variables and subject to substantial risks. Should any such efforts be unsuccessful, we could be subject to additional costs and/or the write-off of our investment in the project or improvement.
Insurance, warranties or performance guarantees may not cover all or any of the lost revenues or increased expenses, including the cost of replacement power. Likewise, the ability to obtain insurance, and the cost of and coverage provided by such insurance, could be affected by events outside our control.
Our cost of compliance with environmental laws and regulations and our commitments, and the cost of compliance with new environmental laws, regulations or commitments could materially adversely affect our results of operations and financial condition.
We are subject to extensive environmental regulation by governmental authorities. In operating our facilities, we are required to comply with numerous environmental laws and regulations and to obtain numerous governmental permits. We may incur significant additional costs beyond those currently contemplated to comply with these requirements. If we fail to comply with these requirements, we could be subject to civil or criminal liabilities and fines. Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to us or our facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions, all of which could result in significant additional costs beyond those currently contemplated to comply with existing requirements.
In conjunction with the building of three new generation units, 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 or if we fail to obtain, maintain or comply with any such approval, the operation and/or construction of our facilities could be stopped, curtailed or modified or become subject to additional costs.
In addition, we may be responsible for any on-site liabilities associated with the environmental condition of facilities that we have acquired, leased or developed, regardless of when the liabilities arose and whether they are known or unknown. In connection with certain acquisitions and sales of assets, we may obtain, or be required to provide, indemnification against certain environmental liabilities. Another party could, depending on the circumstances, assert an environmental claim against us or fail to meet its indemnification obligations to us.
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Our financial condition and results of operations may be materially adversely affected if new federal and/or state legislation or regulations are adopted to address global climate change.
In recent years, a growing concern has emerged about global climate change and how greenhouse gas (GHG) emissions, such as 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), a tax on carbon emissions (carbon-tax), 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 with respect to GHG emissions, including a US Supreme Court case holding that CO2 and other GHG emissions are pollutants subject to regulation under the Clean Air Act. Some commentators believe that the possible outcome from these decisions include future judicial regulation of GHG emissions.
We produce GHG emissions from the combustion of fossil fuels at our generation facilities. For 2008, we estimate that our generation facilities produced 55 million short tons of CO2 based on continuously monitored data reported to and approved by the EPA. The two new lignite-fueled units that achieved substantial completion (as defined in the EPC Agreement for the units) in fall of 2009 and the one new lignite-fueled unit that is expected to achieve substantial completion (as defined in the EPC Agreement for the unit) in mid-2010 will generate additional CO2 emissions. Because a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities, our financial condition and results of operations could be materially adversely affected by the enactment of any legislation or regulation that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes upon those that produce GHG emissions. For example, to the extent a cap-and-trade program is adopted, we may be required to incur material costs to reduce our GHG emissions or to procure emission allowances or credits to comply with such a program. To the extent that the EPA begins to regulate GHGs under the Clean Air Act or the judiciary imposes limits on GHG emissions, we could incur material costs to reduce our GHG emissions. If a significant number of our investors, customers or others refuse to do business with us because of our GHG emissions, it could have a material adverse effect on our results of operations, financial position and liquidity.
Our financial condition and results of operations may be materially adversely affected by the effects of extreme weather conditions.
We could be subject to the effects of extreme weather. Extreme weather conditions could stress our transmission and distribution system or our generation facilities resulting in increased maintenance and capital expenditures. Extreme weather events, including hurricanes or storms or other natural disasters, could be destructive and result in casualty losses that are not ultimately offset by insurance proceeds or in increased capital expenditures or costs, including supply chain costs.
Moreover, an extreme weather event could cause disruption in service to customers due to downed wires and poles or damage to other operating equipment, which could result in us foregoing sales of electricity and lost revenue. Similarly, an extreme weather event might affect the availability of generation and transmission capacity, limiting our ability to source or deliver electricity to where it is needed. These conditions, which cannot be reliably predicted, could have an adverse consequence by requiring us to seek additional sources of electricity when wholesale market prices are high or to seek to sell excess electricity when those market prices are low.
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The rates of Oncor’s electricity delivery business are subject to regulatory review, and may be reduced below current levels, which could adversely impact Oncor’s financial condition and results of operations.
The rates charged by Oncor are regulated by the PUCT and certain cities and are subject to cost-of-service regulation and annual earnings oversight. This regulatory treatment does not provide any assurance as to achievement of earnings levels. Oncor’s rates are regulated based on an analysis of Oncor’s costs and capital structure, as reviewed and approved in a regulatory proceeding. While rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital, there can be no assurance that the PUCT will judge all of Oncor’s costs to have been prudently incurred, that the PUCT will not reduce the amount of invested capital included in the capital structure that Oncor’s rates are based upon, or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of Oncor’s costs, including regulatory assets reported in the balance sheet, and the return on invested capital allowed by the PUCT.
In addition, in connection with the Merger, Oncor has made several commitments to the PUCT regarding its rates. For example, Oncor committed that it will, in rate cases after its 2008 general rate case through proceedings initiated prior to December 31, 2012, support a cost of debt that will be no greater than the then-current cost of debt of electric utilities with investment grade credit ratings equal to Oncor’s ratings as of October 1, 2007. As a result, Oncor may not be able to recover all of its debt costs if they are above those levels.
Our growth strategy, including investment in three new lignite-fueled generation units and Oncor’s capital program, may not be executed as planned, which could adversely impact our financial condition and results of operations.
There can be no guarantee that the execution of our growth strategy will be successful. As discussed below, our growth strategy is dependent upon many factors. Changes in laws, regulations, markets, costs, the outcome of on-going litigation or other factors could negatively impact the execution of our growth strategy, including causing management to change the strategy. Even if we are able to execute our growth strategy, it may take longer than expected, and costs may be higher than expected.
There can be no guarantee that the execution of the lignite-fueled generation development program will be successful. While we have experience in operating lignite-fueled generation facilities, we have limited recent experience in constructing, commissioning and starting-up such facilities. To the extent construction is not managed efficiently and to a timely conclusion, cost overruns may occur, resulting in the overall program costing significantly more than anticipated. This may also result in delays in the expected online dates for the facilities resulting in less overall income than projected. While we believe we can acquire the resources needed to effectively execute this program, we are exposed to the risk that we may not be able to attract and retain skilled labor, at projected rates, for constructing, commissioning and starting-up these new facilities.
Our lignite-fueled generation development program is subject to changes in laws, regulations and policies that are beyond our control. Changes in law, regulation or policy regarding commodity prices, power prices, electricity competition or solid-fuel generation facilities or other related matters could adversely impact this program. In recent years, global warming has received significant media attention, which has resulted in legislators focusing on environmental laws, regulations and policies. Changes in environmental law, regulation or policy, such as regulations of emissions of carbon dioxide, could adversely impact this program. Although we have received permits to construct and operate the new units that are a part of the lignite-fueled generation development program, some of these permits are subject to ongoing litigation. See Item 3, “Legal Proceedings — Litigation Related to Generation Facilities” for further detail regarding such ongoing litigation. An adverse ruling on these matters could materially and adversely effect the implementation of this program.
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Our lignite-fueled generation development program is subject to changes in the electricity market, primarily ERCOT, that are beyond our control. If demand growth is less than expected or if other generation companies build a significant amount of new generation assets in ERCOT, market prices of power could fall such that the new generation capacity becomes uneconomical. In addition, any unanticipated reduction in wholesale electricity prices, market heat rates and natural gas prices, which could occur for a variety of reasons, could adversely impact this program. Even if we enter into hedges to reduce such exposures, we would still be subject to the credit risk of our counterparties.
There can be no guarantee that the execution of Oncor’s capital deployment program for its electricity delivery facilities will be successful, and there can be no assurance that the capital investments Oncor intends to make in connection with its electricity delivery business will produce the desired reductions in cost and improvements to service and reliability. Furthermore, there can be no guarantee that Oncor’s capital investments, including the investment of approximately $1.3 billion (based on ERCOT cost estimates for CREZ construction projects) to construct CREZ-related transmission lines and facilities, will ultimately be recoverable through rates or, if recovered, that they will be recovered on a timely basis. There can also be no assurance that the PUCT’s award of CREZ construction projects will not be delayed, modified or otherwise vacated through judicial or administrative actions. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulation and Rates.”
Ongoing performance improvement initiatives may not achieve desired cost reductions and may instead result in significant additional costs if unsuccessful.
The implementation of performance improvement initiatives identified by management may not produce the desired reduction in costs and if unsuccessful, may instead result in significant additional costs as well as significant disruptions in our operations due to employee displacement and the rapid pace of changes to organizational structure and operating practices and processes. Such additional costs or operational disruptions could have an adverse effect on our businesses and financial prospects.
TXU Energy’s retail business is subject to the risk that sensitive customer data may be compromised, which could result in an adverse impact to its reputation and/or the results of operations of the retail business.
TXU Energy’s retail business requires access to sensitive customer data in the ordinary course of business. Examples of sensitive customer data are names, addresses, account information, historical electricity usage, expected patterns of use, payment history, credit bureau data, credit and debit card account numbers, drivers license numbers, social security numbers and bank account information. TXU Energy’s retail business may need to provide sensitive customer data to vendors and service providers who require access to this information in order to provide services, such as call center operations, to the retail business. If a significant breach occurred, the reputation of TXU Energy’s retail business may be adversely affected, customer confidence may be diminished, or TXU Energy’s retail business may be subject to legal claims, any of which may contribute to the loss of customers and have a negative impact on the business and/or results of operations.
TXU Energy relies on the infrastructure of local utilities or independent transmission system operators to provide electricity to, and to obtain information about, its customers. Any infrastructure failure could negatively impact customer satisfaction and could have a material negative impact on its business and results of operations.
TXU Energy depends on transmission and distribution facilities owned and operated by unaffiliated utilities, as well as Oncor’s facilities, to deliver the electricity it sells to its customers. If transmission capacity is inadequate, TXU Energy’s ability to sell and deliver electricity may be hindered, it may have to forgo sales or it may have to buy more expensive wholesale electricity than is available in the capacity-constrained area. For example, during some periods, transmission access is constrained in some areas of the Dallas-Fort Worth metroplex, where TXU Energy has a significant number of customers. The cost to provide service to these customers may exceed the cost to provide service to other customers, resulting in lower profits. In addition, any infrastructure failure that interrupts or impairs delivery of electricity to TXU Energy’s customers could negatively impact the satisfaction of its customers with its service.
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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 an adverse effect on the company and its financial prospects. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulations and Rates” for a discussion of new rules regarding REP certification.
Changes in technology or increased electricity conservation efforts may reduce the value of our generation plants and/or Oncor’s electricity delivery facilities and may significantly impact our businesses in other ways as well.
Research and development activities are ongoing to improve existing and alternative technologies to produce electricity, including gas turbines, fuel cells, microturbines, photovoltaic (solar) cells and concentrated solar thermal devices. It is possible that advances in these or other technologies will reduce the costs of electricity production from these technologies to a level that will enable these technologies to compete effectively with our traditional generation plants. While demand for electricity has been generally increasing throughout the US, the rate of construction and development of new, more efficient generation facilities may exceed increases in demand in some regional electric markets. Consequently, where we have facilities, the profitability and market value of our generation assets could be significantly reduced. Changes in technology could also alter the channels through which retail customers buy electricity. To the extent self-generation facilities become a more cost-effective option for certain customers, our revenues could be materially reduced.
Also, electricity demand could be reduced by increased conservation efforts and advances in technology, which could likewise significantly reduce the value of our generation assets and electricity delivery facilities. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. Effective energy conservation by our customers could result in reduced energy demand or significantly slow the growth in demand. Such reduction in demand could materially reduce our revenues. Furthermore, we may incur increased capital expenditures if we are required to invest in conservation measures.
Our revenues and results of operations may be adversely impacted by decreases in market prices of power due to the development of wind generation power sources.
A significant amount of investment in wind generation in the ERCOT market over the past few years has increased overall wind power generation capacity. Generally, the increased capacity has led to lower wholesale electricity prices (driven by lower market heat rates) in the zones at or near wind generation development, especially in, but not exclusive to, the ERCOT West zone where most of the new wind power generation is located. As a result, the profitability of our generation facilities and power purchase contracts, including certain wind generation power purchase contracts, has been impacted and could be further impacted by the effects of the wind power generation, and the value could significantly decrease if wind power generation has a material sustained effect on market heat rates.
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Our revenues and results of operations may be adversely impacted as ERCOT transitions the current zonal market structure to a nodal wholesale market.
Substantially all of our competitive businesses are located in the ERCOT market, which is currently in the process of transitioning from a zonal market structure with four congestion management zones to a nodal market structure that will directly manage congestion on a localized basis. In a nodal market, the prices received and paid for power will be based on pricing determined at specific interconnection points on the transmission grid (i.e., Locational Marginal Pricing), which could result in lower revenues or higher costs for our competitive businesses. This market structure change could have a significant impact on the profitability and value of our competitive businesses depending on how the Locational Marginal Pricing develops. See Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Regulations and Rates — Wholesale Market Design.”
Our future results of operations may be negatively impacted by settlement adjustments determined by ERCOT related to prior periods.
ERCOT is the independent system operator that is responsible for maintaining reliable operation of the bulk electric power supply system in the ERCOT market. Its responsibilities include the clearing and settlement of electricity volumes and related ancillary services among the various participants in the deregulated Texas market. Settlement information is due from ERCOT within two months after the operating day, and true-up settlements are due from ERCOT within six months after the operating day. Likewise, ERCOT has the ability to resettle any operating day at any time after the six month settlement period, usually the result of a lingering dispute, an alternative dispute resolution process or litigated event. As a result, we are subject to settlement adjustments from ERCOT related to prior periods, which may result in charges or credits impacting our future reported results of operations.
Our results of operations and financial condition could be negatively impacted by any development or event beyond our control that causes economic weakness in the ERCOT market.
We derive substantially all of our revenues from operations in the ERCOT market, which covers approximately 75% of the geographical area in the State of Texas. As a result, regardless of the state of the economy in areas outside the ERCOT market, economic weakness in the ERCOT market could lead to reduced demand for electricity in the ERCOT market. Such a reduction could have a material negative impact on our results of operations and financial condition.
EFH Corp.’s (or any applicable subsidiary’s) credit ratings could negatively affect EFH Corp.’s (or the pertinent subsidiary’s) ability to access capital and could require EFH Corp. or its subsidiaries to post collateral or repay certain indebtedness.
Downgrades in EFH Corp.’s or any of its applicable subsidiaries’ long-term debt ratings generally cause borrowing costs to increase and the potential pool of investors and funding sources to decrease and could trigger liquidity demands pursuant to the terms of new commodity contracts, leases or other agreements. In November 2009, the credit rating agencies announced certain rating actions shortly after completion of the EFH Corp. debt exchange transaction discussed in Note 12 to Financial Statements. S&P established B+ ratings for the new EFH Corp. 9.75% Notes and EFIH Notes. Moody’s affirmed its Caa1 corporate family rating and negative outlook for EFH Corp. and TCEH but upgraded its probability of default rating to Caa2 from Ca as it determined that the final transaction results did not represent a “distressed exchange.” In addition, Moody’s established Caa3 ratings for the new EFH Corp. 9.75% Notes and EFIH Notes and completed upgrades of certain securities due to results of the exchange. Fitch established a rating of B+ on the new EFH Corp. 9.75% Notes and EFIH Notes resulting from the exchange and downgraded its ratings of the EFH Corp. 10.875% and Toggle Notes by one notch to B from B+. Additionally, Fitch affirmed its ratings and outlook for EFH Corp., EFC Holdings and TCEH. The ratings and stable outlook for Oncor were unaffected by the exchange and were affirmed by all three agencies. Future transactions by EFH Corp. or any of its subsidiaries, including the issuance of additional debt or the consummation of a transaction similar to the November 2009 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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Continued market volatility may have impacts on our businesses and financial condition that we currently cannot predict.
Because our operations are capital intensive, we expect to rely over the long-term upon access to financial markets (particularly the attainment of liquidity facilities) as a significant source of liquidity for capital requirements not satisfied by cash-on-hand, operating cash flows or our revolving credit facilities. Recently, the capital and credit markets have been experiencing extreme volatility and disruption. Our ability to access the capital or credit markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our flexibility to react to changing economic and business conditions. In addition, the cost of debt financing may be materially impacted by these market conditions. Accordingly, there can be no assurance that the capital and credit markets will continue to be a reliable or acceptable source of short-term or long-term financing for us. Additionally, disruptions in the capital and credit markets could have a broader impact on the economy in general in ways that could lead to reduced electricity usage, which could have a negative impact on our revenues, or have an impact on our customers, counterparties and/or lenders, causing them to fail to meet their obligations to us.
Our liquidity needs could be difficult to satisfy, particularly during times of uncertainty in the financial markets and/or during times when there are significant changes in commodity prices. The inability to access liquidity, particularly on favorable terms, could materially adversely affect results of operations and/or financial condition.
Our businesses are capital intensive. We rely on access to financial markets and liquidity facilities as a significant source of liquidity for capital requirements not satisfied by cash-on-hand or operating cash flows. The inability to raise capital on favorable terms or access liquidity facilities, particularly during times of uncertainty similar to that which has recently been experienced in the financial markets, could impact our ability to sustain and grow our businesses and would likely increase capital costs. Our access to the financial markets and liquidity facilities could be adversely impacted by various factors, such as:
| • | changes in financial markets that reduce available credit or the ability to obtain or renew liquidity facilities on acceptable terms; |
| • | economic weakness in the ERCOT or general 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 EFH Corp.’s or its applicable subsidiaries’ liquidity facilities that affects the ability of such lender(s) to make loans to EFH Corp. or its subsidiaries; |
| • | 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 financial condition and results of operations.
In the event that the governmental agencies that regulate the activities of our businesses determine that the creditworthiness of any such business is inadequate to support our activities, such agencies could require us to provide additional cash or letter of credit collateral in substantial amounts to qualify to do business.
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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 and financial condition.
We provide pension benefits based on either a traditional defined benefit formula or a cash balance formula and also provide certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from us. Our costs of providing such benefits and related funding requirements are dependent upon numerous factors, assumptions and estimates and are subject to changes in these factors, assumptions and estimates, including the market value of the assets funding 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 substantial dislocation in the financial markets that began in 2008 caused the value of the investments that fund our pension and OPEB plans to significantly differ from, and may alter the values and actuarial assumptions we use to calculate, our projected future pension plan expense and OPEB costs. A continuation or further decline in the value of these investments could increase the expenses of the pension plan and the costs of the OPEB plans and related funding requirements in the future. Our costs of providing such benefits and related funding requirements are also subject to changing employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in financial market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.
As was the case in the fourth quarter 2008 (as discussed in Notes 1 and 3 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 financial condition and results of operations.
In accordance with accounting standards, goodwill and certain other indefinite-lived intangible assets that are not subject to amortization are reviewed annually or more frequently for impairment, if certain conditions exist, and may be impaired. Any reduction in or impairment of the value of goodwill or other intangible assets will result in a charge against earnings, which could cause a material adverse impact on our reported results of operations and financial position.
The loss of the services of our key management and personnel could adversely affect our ability to operate our businesses.
Our future success will depend on our ability to continue to attract and retain highly qualified personnel. We compete for such personnel with many other companies, in and outside our industry, government entities and other organizations. We may not be successful in retaining current personnel or in hiring or retaining qualified personnel in the future. Our failure to attract new personnel or retain existing personnel could have a material adverse effect on our businesses.
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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 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 September 2007, an administrative appeal challenging the order of the TCEQ issuing the air permit for construction and operation of the Oak Grove generation facility in Robertson County, Texas was filed in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments, and remand the matter back to TCEQ for further proceedings. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before the TCEQ and the State Office of Administrative Hearings (SOAH) seeking to challenge the TCEQ’s issuance of the Oak Grove air permit and asking the District Court to remand the matter to the SOAH for further proceedings. Finally, the plaintiffs in these two additional lawsuits filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. One of the plaintiffs asked the District Court to consolidate all these proceedings, and the Attorney General of Texas, on behalf of TCEQ, filed pleas to the jurisdiction seeking dismissal of all but the administrative appeal. In May 2009, the District Court dismissed the claims that contest the merits of the TCEQ’s permitting decision, but declined to dismiss the claims that contest the process by which the TCEQ handled the permit application. Oak Grove Management Company LLC (a subsidiary of TCEH) has subsequently intervened in these proceedings and has filed its own pleas to the jurisdiction asking the court to dismiss the remaining collateral attack claims. In October 2009, one of the plaintiffs ended its legal challenge to the permit. In December 2009, the Attorney General and Oak Grove Management Company LLC filed pleadings asking the court to dismiss the administrative appeal challenging the permit for want of prosecution by the plaintiffs. In January 2010, the court denied that request and set the case for a hearing on the merits on June 16, 2010. We believe the Oak Grove air permit granted by the TCEQ was issued in accordance with applicable law. There can be no assurance that the outcome of these matters will not adversely impact the Oak Grove project.
In June and September 2008, administrative appeals were filed in the State District Court of Travis County, Texas to challenge the administrative action of the TCEQ Executive Director in issuing an air permit alteration for the previously-permitted construction and operation of the Sandow 5 generation facility in Milam County, Texas, and the failure of the TCEQ to overturn that administrative action. Plaintiffs asked that the District Court reverse the issuance of the permit alteration. The Attorney General of Texas, on behalf of TCEQ, is defending the issuance of the permit alteration. Sandow Power (a subsidiary of TCEH) intervened in support of the TCEQ. The District Court issued its ruling in November 2009 upholding the TCEQ’s issuance of the permit alteration. The plaintiffs did not appeal the court’s order by the deadline for such appeal. Thus, the matter has concluded favorably for EFH Corp.
In February 2010, the Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Big Brown generation facility. This notice is similar to the notice that Luminant received in July 2008 with respect to its Martin Lake generation facility. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.
In July 2008, Alcoa Inc. filed a lawsuit in the State District Court of Milam County, Texas against Luminant Generation and Luminant Mining (wholly-owned subsidiaries of TCEH), later adding EFH Corp., a number of its subsidiaries, Texas Holdings and Texas Energy Future Capital Holdings LLC as parties to the suit. The lawsuit makes various claims concerning the operation of the Sandow Unit 4 generation facility and the Three Oaks lignite mine, including claims for breach of contract, breach of fiduciary duty, fraud, tortious interference, civil conspiracy and conversion. The plaintiff requests money damages of no less than $500 million, declaratory judgment, rescission and other forms of equitable relief. An agreed scheduling order is currently in place setting trial for May 2010. While we are unable to estimate any possible loss or predict the outcome of this litigation, we believe the plaintiff’s claims made in this litigation are without merit and, accordingly, intend to vigorously defend this litigation.
Regulatory Investigations and Reviews
In June 2008, the EPA issued a request for information to TCEH under EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.
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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. | SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS |
None.
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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 14 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 18, 2010 was 117.
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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, | Year Ended December 31, | |||||||||||||||||||||||
| 2009 | 2008 | 2007 | 2007 | 2006 | 2005 | |||||||||||||||||||||
Operating revenues | $ | 9,546 | $ | 11,364 | $ | 1,994 | $ | 8,044 | $ | 10,703 | $ | 10,826 | ||||||||||||||
Income (loss) from continuing operations before extraordinary loss and cumulative effect of changes in accounting principles | 408 | (9,998 | ) | (1,361 | ) | 699 | 2,465 | 1,775 | ||||||||||||||||||
Income from discontinued operations, net of tax effect | — | — | 1 | 24 | 87 | 5 | ||||||||||||||||||||
Extraordinary loss, net of tax effect | — | — | — | — | — | (50 | ) | |||||||||||||||||||
Cumulative effect of changes in accounting principles, net of tax effect | — | — | — | — | — | (8 | ) | |||||||||||||||||||
Preference stock dividends | — | — | — | — | — | 10 | ||||||||||||||||||||
Net income (loss) | 408 | (9,998 | ) | (1,360 | ) | 723 | 2,552 | 1,712 | ||||||||||||||||||
Net (income) loss attributable to noncontrolling interests | (64 | ) | 160 | — | — | — | — | |||||||||||||||||||
Net income (loss) attributable to EFH Corp. | 344 | (9,838 | ) | (1,360 | ) | 723 | 2,552 | 1,712 | ||||||||||||||||||
Ratio of earnings to fixed charges (a) | 1.24 | — | — | 2.30 | 5.11 | 3.80 | ||||||||||||||||||||
Ratio of earnings to combined fixed charges and preference dividends (a) | 1.24 | — | — | 2.30 | 5.11 | 3.74 | ||||||||||||||||||||
Embedded interest cost on long-term debt — end of period (b) | 7.2 | % | 9.2 | % | 9.5 | % | 6.5 | % | 6.6 | % | 6.3 | % | ||||||||||||||
Capital expenditures, including nuclear fuel | $ | 2,545 | $ | 3,015 | $ | 716 | $ | 2,542 | $ | 2,337 | $ | 1,148 | ||||||||||||||
See Notes to Financial Statements.
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EFH CORP. AND SUBSIDIARIES
SELECTED FINANCIAL DATA (CONTINUED)
(millions of dollars, except ratios)
| Successor | Predecessor | |||||||||||||||||||||
| December 31, | December 31, | |||||||||||||||||||||
| 2009 | 2008 | 2007 | 2006 | 2005 | ||||||||||||||||||
Total assets — end of year | $ | 59,662 | $ | 59,263 | $ | 64,804 | $ | 27,216 | $ | 27,978 | ||||||||||||
Property, plant & equipment — net — end of year | $ | 30,108 | $ | 29,522 | $ | 28,650 | $ | 18,569 | $ | 17,006 | ||||||||||||
Goodwill and intangible assets — end of year | $ | 17,192 | $ | 17,379 | $ | 27,319 | $ | 729 | $ | 728 | ||||||||||||
Capitalization — end of year | ||||||||||||||||||||||
Equity-linked debt securities | $ | — | $ | — | $ | — | $ | — | $ | 179 | ||||||||||||
All other long-term debt, less amounts due currently | 41,440 | 40,838 | 38,603 | 10,631 | 11,153 | |||||||||||||||||
Preferred stock of subsidiaries (not subject to mandatory redemption) (c) | — | — | — | — | — | |||||||||||||||||
EFH Corp. common stock equity | (3,247 | ) | (3,673 | ) | 6,685 | 2,140 | 475 | |||||||||||||||
Noncontrolling interests in subsidiaries | 1,411 | 1,355 | — | — | — | |||||||||||||||||
Total | $ | 39,604 | $ | 38,520 | $ | 45,288 | $ | 12,771 | $ | 11,807 | ||||||||||||
Capitalization ratios — end of year | ||||||||||||||||||||||
Equity-linked debt securities | — | % | — | % | — | % | — | % | 1.5 | % | ||||||||||||
All other long-term debt, less amounts due currently | 104.6 | 106.0 | 85.2 | 83.2 | 94.5 | |||||||||||||||||
Preferred stock of subsidiaries (c) | — | — | — | — | — | |||||||||||||||||
EFH Corp. common stock equity | (8.2 | ) | (9.5 | ) | 14.8 | 16.8 | 4.0 | |||||||||||||||
Noncontrolling interests in subsidiaries | 3.6 | 3.5 | — | — | — | |||||||||||||||||
Total | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | 100.0 | % | ||||||||||||
Short-term borrowings – end of year | $ | 1,569 | $ | 1,237 | $ | 1,718 | $ | 1,491 | $ | 798 | ||||||||||||
Long-term debt due currently – end of year | $ | 417 | $ | 385 | $ | 513 | $ | 485 | $ | 1,250 | ||||||||||||
| (a) | Fixed charges exceeded “earnings” (net loss) by $10.469 billion and $2.034 billion for the year ended December 31, 2008 and for the period from October 11, 2007 through December 31, 2007, respectively. |
| (b) | Represents the annual interest using year-end rates for variable rate debt and reflecting the effects of interest rate swaps (excluding unrealized mark-to-market gains or losses) and amortization of any discounts, premiums, issuance costs and any deferred gains/losses on reacquisitions divided by the carrying value of the debt plus or minus the unamortized balance of any discounts, premiums, issuance costs and gains/losses on reacquisitions at the end of the year. |
| (c) | Preferred stock outstanding at the end of 2008, 2007, 2006 and 2005 has a stated amount of $51 thousand. There was no outstanding preferred stock at the end of 2009. |
Note: Although EFH Corp. continued as the same legal entity after the Merger, its “Selected 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 2008 were significantly impacted by impairment charges related to goodwill, trade name and emission allowances intangible assets and natural gas-fueled generation facilities.
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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 (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 | ||||||
| First Quarter | Second Quarter | Third Quarter (b) | Fourth Quarter (c) | |||||||||||||
2008: | ||||||||||||||||
Operating revenues | $ | 2,354 | $ | 2,951 | $ | 3,695 | $ | 2,364 | ||||||||
Net income (loss) | (1,269 | ) | (3,331 | ) | 3,617 | (9,015 | ) | |||||||||
Net loss attributable to noncontrolling interests | — | — | — | 160 | ||||||||||||
Net income (loss) attributable to EFH Corp. | $ | (1,269 | ) | $ | (3,331 | ) | $ | 3,617 | $ | (8,855 | ) | |||||
| (a) | Net income (loss) amounts include the effects of impairment charge related to goodwill (see Note 3 to Financial Statements). |
| (b) | Net income (loss) amounts include the effects of impairment charge related to emission allowances intangible assets (see Note 3 to Financial Statements). |
| (c) | Net income (loss) amounts include the effects of impairment charges related to goodwill, trade name and emission allowances intangible assets and natural gas-fueled generation facilities (see Notes 3 and 5 to 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, 2009, 2008 and 2007 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-based holding company conducting operations principally through our TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority-owned (approximately 80%) subsidiary engaged in regulated electricity transmission and distribution operations in Texas. Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor. See Note 1 to Financial Statements for a description of the material features of these “ring-fencing” measures and Note 15 to Financial Statements for discussion of noncontrolling interests sold by Oncor.
Operating Segments
We have aligned and report our business activities as two operating segments: the Competitive Electric segment and the Regulated Delivery segment. The Competitive Electric segment is principally comprised of TCEH. The segment also includes equipment salvage and resale activities related to the cancellation of the development of eight new coal-fueled generation units in 2007. The Regulated Delivery segment is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary.
See Note 24 to Financial Statements for further information regarding reportable business segments.
Significant Activities and Events
Long-Term Hedging Program — TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas. Under the program, the company has entered into market transactions involving natural gas-related financial instruments, and as of December 31, 2009, has effectively sold forward approximately 1.6 billion MMBtu of natural gas (equivalent to the natural gas exposure of approximately 200,000 GWh at an assumed 8.0 market heat rate) for the period from January 1, 2010 through December 31, 2014 at weighted average annual hedge prices ranging from $7.80 per MMBtu to $7.19 per MMBtu. These transactions, as well as forward power sales, have effectively hedged an estimated 68% of the natural gas price exposure related to TCEH’s expected generation output for the period beginning January 1, 2010 and ending December 31, 2014 (on an average basis for such period and assuming an 8.0 market heat rate). The hedges were entered into with the continuing expectation that wholesale electricity prices in ERCOT will be highly correlated with natural gas prices, which is expected to be the marginal fuel for the purpose of setting electricity prices approximately 75% to 90% of the time. If the correlation changes in the future, the cash flows targeted under the long-term hedging program may not be achieved.
The long-term hedging program is comprised primarily of contracts with prices based on the New York Mercantile Exchange (NYMEX) Henry Hub pricing point. However, because there are other local and regional natural gas pricing points such as Houston Ship Channel, future wholesale power prices in ERCOT may not correlate as closely to the Henry Hub pricing as other pricing points, which could decrease the effectiveness of the positions in the long-term hedging program in mitigating power price exposure. The company has hedged more than 95% of the Houston Ship Channel versus Henry Hub pricing point risk for 2010.
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The company has entered into related put and call transactions (referred to as collars), primarily for year 2014 of the program, that effectively hedge natural gas prices within a range. These transactions represented approximately 6% of the positions in the long-term hedging program at December 31, 2009, with the approximate weighted average strike prices under the collars being a floor of $7.80 per MMBtu and a ceiling of $11.75 per MMBtu. The company expects to use financial instruments, including collars, in future hedging activity under the long-term hedging program.
The following table summarizes the natural gas hedges in the long-term hedging program as of December 31, 2009:
Measure | 2010 | 2011 | 2012 | 2013 | 2014 | Total | ||||||||
Natural gas hedge volumes (a) | mm MMBtu | ~240 | ~447 | ~490 | ~300 | ~97 | ~1,574 | |||||||
Weighted average hedge price (b) | $/MMBtu | ~7.79 | ~7.56 | ~7.36 | ~7.19 | ~7.80 | — | |||||||
Weighted average market price (c) | $/MMBtu | ~5.79 | ~6.34 | ~6.53 | ~6.67 | ~6.84 | — |
| (a) | Where collars are reflected, the volumes are estimated based on the natural gas price sensitivity (i.e., delta position) of the derivatives. The notional volumes for collars are approximately 150 million MMBtu, which corresponds to a delta position of approximately 97 million MMBtu in 2014. |
| (b) | Weighted average hedge prices are based on NYMEX Henry Hub prices of forward natural gas sales positions in the long-term hedging program (excluding the impact of offsetting purchases for rebalancing and pricing point basis transactions). Where collars are reflected, sales price represents the collar floor price. |
| (c) | Based on NYMEX Henry Hub prices. |
Changes in the fair value of the instruments in the long-term hedging program are being recorded as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities in the statement of income, which has and could continue to result in significant volatility in reported net income. Based on the size of the long-term hedging program as of December 31, 2009, a $1.00/MMBtu change in natural gas prices across the hedged period would result in the recognition of up to approximately $1.6 billion in pretax unrealized mark-to-market gains or losses.
The reported unrealized mark-to-market net gain related to the long-term hedging program for the year ended December 31, 2009 totaled $1.107 billion. This amount reflects a $1.857 billion net gain due to the effect of lower forward prices of natural gas on the value of positions in the program, which was partially offset by net losses of $750 million representing reversals of previously recorded unrealized gains on positions that settled in the period. The reported unrealized mark-to-market net gain related to the long-term hedging program for the year ended December 31, 2008 totaled $2.587 billion reflecting declines in forward prices of natural gas in 2008. Given the volatility of natural gas prices, it is not possible to predict future reported unrealized mark-to-market gains or losses and the actual gains or losses that will ultimately be realized upon settlement of the hedge positions in future years. If natural gas prices at settlement are lower than the prices of the hedge positions, the hedges are expected to mitigate the otherwise negative effect on earnings of lower wholesale electricity prices. However, if natural gas prices at settlement are higher than the prices of the hedge positions, the hedges are expected to dampen the otherwise positive effect on earnings of higher wholesale electricity prices and will in this context be viewed as having resulted in an opportunity cost. The cumulative unrealized mark-to-market net gain related to positions in the long-term hedging program totaled $1.978 billion and $871 million at December 31, 2009 and December 31, 2008, respectively. These values can change materially as market conditions change.
As of December 31, 2009, more than 95% of the long-term hedging program transactions were directly or indirectly secured by a first-lien interest in TCEH’s assets (including the transactions supported by the TCEH Commodity Collateral Posting Facility — see discussion below under “Financial Condition — Liquidity and Capital Resources”) thereby reducing the cash and letter of credit collateral requirements for the hedging program.
See “Key Risks and Challenges — Substantial Leverage, Uncertain Financial Markets and Liquidity Risk” and “ — Natural Gas Price and Market Heat Rate Exposure.”
Debt Exchanges and Issuances — See Note 12 to Financial Statements for discussion of debt exchange offers completed in November 2009 and the issuance of additional notes in January 2010.
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TCEH Interest Rate Swap Transactions — As of December 31, 2009, TCEH had entered into a series of interest rate swaps that effectively fix the interest rates at between 7.3% and 8.3% on $16.30 billion principal amount of its senior secured debt maturing from 2010 to 2014. All of these swaps were entered into prior to January 1, 2009. Taking into consideration these swap transactions, approximately 10% of our total long-term debt portfolio at December 31, 2009 was exposed to variable interest rate risk. TCEH also entered into interest rate basis swap transactions, which further reduce the fixed (through swaps) borrowing costs, related to an aggregate of $16.25 billion principal amount of senior secured debt. We may enter into additional interest rate hedges from time to time. Unrealized mark-to-market net gains and losses related to all TCEH interest rate swaps, which are reported in interest expense and related charges, totaled $696 million in net gains for the year ended December 31, 2009 and $1.477 billion in net losses for the year ended December 31, 2008. The cumulative unrealized mark-to-market net liability related to all TCEH interest rate swaps totaled $1.212 billion and $1.909 billion at December 31, 2009 and 2008, respectively, of which $194 million and $364 million (both pre-tax), respectively, was reported in accumulated other comprehensive income. These fair values can change materially as market conditions change, which could result in significant volatility in reported net income. See discussion in Note 12 to Financial Statements regarding various interest rate swap transactions.
Texas Generation Facilities Development —TCEH is nearing completion of a program to develop three lignite-fueled generation units (2 units at Oak Grove and 1 unit at Sandow) in Texas with a total estimated capacity of approximately 2,200 MW. The Sandow unit and the first Oak Grove unit achieved substantial completion (as defined in the EPC Agreements for the units) effective September 30, 2009 and December 22, 2009, respectively. Accordingly, the company has operational control of these units. We began depreciating these units and recognizing revenues and fuel costs for accounting purposes in the fourth quarter 2009. The second Oak Grove unit, which is in the commissioning and start-up phase, synchronized to the grid in January 2010 and is expected to achieve substantial completion (as defined in the EPC Agreement for the unit) in mid-2010. Aggregate cash capital expenditures for these three units are expected to total approximately $3.25 billion including all construction, site preparation and mining development costs, of which approximately $3.1 billion was spent as of December 31, 2009. Total recorded costs, including purchase accounting fair value adjustments and capitalized interest, are expected to total approximately $4.8 billion upon completion of the units, and the balance was $4.6 billion as of December 31, 2009. See discussion in Note 13 to Financial Statements regarding contingencies related to these units.
Nuclear Generation Development —In September 2008, a subsidiary of TCEH filed a combined operating license application with the NRC for two new nuclear generation units, each with approximately 1,700 MW (gross capacity), at its existing Comanche Peak nuclear generation site. In connection with the filing of the application, in January 2009, subsidiaries of TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, Comanche Peak Nuclear Power Company (CPNPC), to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. The TCEH subsidiary owns an 88% interest in CPNPC, and a MHI subsidiary owns a 12% interest.
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.
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Idling of Natural Gas-Fueled Units — In February 2009, we notified ERCOT of plans to retire 11 of our natural gas-fueled units, totaling 2,251 MW of capacity (2,341 MW installed nameplate capacity), in May 2009, and mothball (idle) an additional four units, totaling 1,651 MW of capacity (1,675 MW of installed nameplate capacity), in September 2009. In May and September 2009, we entered into reliability-must-run (RMR) agreements for the remainder of 2009 with ERCOT for the operation of one unit originally planned to be retired with 112 MW of capacity (115 MW of installed nameplate capacity) and one unit planned to be mothballed with 515 MW of capacity (540 MW of installed nameplate capacity), respectively. In December 2009, we entered into RMR agreements with ERCOT for these same two units for January through November 2010. The other units were retired in May 2009 or mothballed in September 2009 as originally planned. An impairment charge of $229 million related to the carrying value of these units was recorded in the fourth quarter of 2008.
Global Climate Change —See Items 1 and 2 “Business and Properties – Environmental Regulations and Related Considerations” for discussion of global climate change and the effects on the company.
Impairment of Goodwill— Financial market conditions had a significant effect on our 2008 assessment of the carrying value of goodwill. We recorded a total goodwill impairment charge of $8.950 billion (which was not deductible for income tax purposes) in 2008 and 2009, primarily arising from the dislocation in the capital markets that had increased interest rate spreads and the resulting discount rates used in estimating fair values and the effects of declines in market values of debt and equity securities of comparable companies.
This non-cash impairment did not cause EFH Corp. or its subsidiaries to be in default under any of their respective debt covenants or impact counterparty trading agreements or have a material impact on liquidity.
See Note 3 to Financial Statements and “Application of Critical Accounting Policies” below for more information on the goodwill impairment charge.
Oncor Technology Initiatives— Oncor continues to invest in technology initiatives that include development of a modernized grid through the replacement of existing meters with advanced digital metering equipment and development of advanced digital communication, data management, real-time monitoring and outage detection capabilities. This modernized grid is expected to produce electricity service reliability improvements and provide the potential for additional products and services from REPs that will enable businesses and consumers to better manage their electricity usage and costs. Oncor’s plans provide for the full deployment of over three million advanced meters by the end of 2012 to all residential and most non-residential retail electricity customers in Oncor’s service area. The advanced meters can be read remotely, rather than by a meter reader physically visiting the location of each meter. Advanced meters facilitate automated demand side management, which allows consumers to monitor the amount of electricity they are consuming and adjust their electricity consumption habits.
As of December 31, 2009, Oncor has installed approximately 660 thousand advanced digital meters, including approximately 620 thousand during the year ended December 31, 2009. As the new meters are integrated, Oncor reports 15-minute interval, billing-quality electricity consumption data to ERCOT for market settlement purposes. The data makes it possible for REPs to support new programs and pricing options. Cumulative capital expenditures for the deployment of the advanced meter system totaled $196 million as of December 31, 2009.
As discussed below under “Regulation and Rates,” Oncor has implemented a rate surcharge effective January 1, 2009 to recover its investment in the advanced meter deployment.
Oncor Matters with the PUCT —See discussion of these matters, including the awarded construction of $1.3 billion of transmission lines and a rate case with the PUCT, below under “Regulation and Rates.”
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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.
Substantial Leverage, Uncertain Financial Markets and Liquidity Risk
Our substantial leverage, resulting in large part from debt incurred to finance the Merger, requires significant cash flows to be dedicated to interest and principal payments and could adversely affect our ability to raise additional capital to fund operations, limit our ability to react to changes in the economy, our industry or our business, and expose us to interest rate risk to the extent not hedged. Short-term borrowings and long-term debt, including amounts due currently, totaled $43.426 billion at December 31, 2009. Taking into consideration interest-rate swap transactions, as of December 31, 2009 approximately 90% of our total long-term debt portfolio is subject to fixed interest rates, at a weighted average interest rate of 8.95%. Interest payments on long-term debt in 2010 are expected to total approximately $3.059 billion, and principal payments are expected to total approximately $340 million.
While we believe our cash on hand and cash flow from operations combined with availability under existing credit facilities provide sufficient liquidity to fund current and projected expenses and capital requirements for 2010 (see “Financial Condition – Liquidity and Capital Resources” section below), there can be no assurance that counterparties to our credit facilities will perform as expected through the maturity dates or hedging and trading counterparties, particularly related to the long-term hedging program, will meet their obligations to us. Failure of such counterparties to meet their obligations or substantial changes in financial markets, the economy, the requirements of regulators or our industry or operations could result in constraints in our liquidity. See discussion of credit risk in Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” and discussion of credit facilities in “Financial Condition – Liquidity and Capital Resources” and in Note 12 to Financial Statements. Also, as a result of the financial crisis that arose in 2008, there has been a reduction of available counterparties for our hedging and trading activities, particularly for longer-dated transactions, which could impact our ability to hedge our commodity price and interest rate exposure to desired levels at reasonable costs. However, traditional counterparties with physical assets to hedge, as well as financial institutions and other parties, continue to participate in the markets.
A substantial amount of our indebtedness is scheduled to mature in the period from 2014 through 2017. We are focused on improving the balance sheet and expect to opportunistically look for ways to reduce the amount and extend the weighted average maturity of our outstanding debt. Progress to date on this initiative includes the August 2009 amendment to the Credit Agreement governing the TCEH Senior Secured Facilities that provides additional flexibility in restructuring debt obligations, the debt exchanges completed in November 2009 and the January 2010 issuance of $500 million of senior secured notes to be used for general corporate purposes, including but not limited to, repurchase of outstanding indebtedness. See Note 12 to 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 the effects of weather, changes in industrial demand, supply availability, and other economic and market factors and such prices have been very volatile in recent years. Since 2005, forward natural gas prices ranged from below $4 per MMBtu to above $13 per MMBtu. The wholesale market price of power divided by the market price of natural gas represents the market heat rate. Market heat rate movements also affect wholesale electricity prices. Market heat rate reflects the efficiency of the marginal supplier (generally natural gas-fueled generation facilities) in generating electricity.
In contrast to our natural gas-fueled generation facilities, changes in natural gas prices have no significant effect on the cost of generating electricity from our nuclear and lignite/coal-fueled plants. All other factors being equal, these baseload generation assets, which provided 70% of supply volumes in 2009, increase or decrease in value as natural gas prices and market heat rates rise or fall, respectively, because of the effect of natural gas prices setting marginal wholesale power prices in ERCOT.
With the exposure to variability of natural gas prices, retail sales price management and hedging activities are critical to the profitability of the business and maintaining consistent cash flow levels.
Our approach to managing commodity price risk focuses on the following:
| • | employing disciplined hedging and risk management strategies through physical and financial energy-related (electricity and natural gas) contracts intended to partially hedge gross margins; |
| • | continuing reduction of fixed costs to better withstand gross margin volatility; |
| • | following a retail pricing strategy that appropriately reflects the magnitude and costs of commodity price and liquidity risk, and |
| • | improving retail customer service to attract and retain high-value customers. |
As discussed above under “Significant Activities and Events,” we have implemented a long-term hedging program to mitigate the risk of future declines in wholesale electricity prices due to declines in natural gas prices.
The following sensitivity table provides estimates of the potential impact (in $millions) of movements in natural gas and certain other commodity prices and market heat rates on realized pre-tax earnings for the periods presented. The estimates related to price sensitivity are based on TCEH’s unhedged position and forward prices as of December 31, 2009, which for natural gas reflects estimates of electricity generation less amounts hedged through the long-term natural gas hedging program and amounts under existing wholesale and retail sales contracts. On a rolling twelve-month basis, the substantial majority of retail sales under month-to-month arrangements are deemed to be under contract.
| Balance 2010 (a) | 2011 | 2012 | 2013 | 2014 | |||||||||||||
$1.00/MMBtu change in gas price (b) | $ | ~9 | $ | ~45 | $ | ~89 | $ | ~308 | $ | ~512 | |||||||
0.1/MMBtu/MWh change in market heat rate (c) | $ | ~10 | $ | ~44 | $ | ~54 | $ | ~57 | $ | ~59 | |||||||
$1.00/gallon change in diesel fuel price | $ | ~1 | $ | ~1 | $ | ~2 | $ | ~53 | $ | ~57 | |||||||
$10.00/pound change in uranium/nuclear fuel | $ | — | $ | — | $ | ~1 | $ | ~5 | $ | ~4 | |||||||
| (a) | Balance of 2010 is from February 1, 2010 through December 31, 2010. |
| (b) | Assumes conversion of electricity positions based on an approximate 8.0 market heat rate with natural gas being on the margin 75% to 90% of the time (i.e., when coal is forecast to be on the margin, no natural gas position is assumed to be generated). |
| (c) | Based on Houston Ship Channel natural gas prices as of December 31, 2009. |
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Our market heat rate exposure is impacted by changes in the mix of generation assets, such as generation capacity increases, particularly increases in lignite/coal- and nuclear-fueled generation capacity, as well as wind capacity, which could result in lower market heat rates. We expect that decreases in market heat rates would decrease the value of our generation assets because lower market heat rates generally result in lower wholesale electricity prices, and vice versa. We mitigate market heat rate risk through retail and wholesale electricity sales contracts and shorter-term market heat rate hedging transactions. We evaluate opportunities to mitigate market heat rate risk over extended periods through longer-term electricity sales contracts where practical considering pricing, credit, liquidity and related factors.
On an ongoing basis, we will continue monitoring our overall commodity risks and seek to balance our portfolio based on our desired level of exposure to natural gas prices and market heat rates and potential changes to our operational forecasts of overall generation and consumption (which is also subject to volatility resulting from customer churn, weather, economic and other factors) in our native and growth business. Portfolio balancing may include the execution of incremental transactions, including heat rate hedges, the unwinding of existing transactions and the substitution of natural gas hedges with commitments for the sale of electricity at fixed prices. As a result, commodity price exposures and their effect on earnings could materially change from time to time.
The Obama Administration has proposed financial market reforms with respect to the currently unregulated Over-the-Counter (OTC) financial derivatives market. As a result, the US House of Representative has approved a bill to regulate OTC derivatives. The bill would require certain entities to clear OTC derivatives that are currently traded on the bilateral market through exchanges, which require that all collateral be in the form of cash. We have entered into a significant number of asset-backed OTC derivatives to hedge risks associated with commodity and interest rate exposure. The US House of Representatives legislation would not require us to clear our OTC derivatives through exchanges. However, other proposals would have required such clearing, and it is not evident what, if any, US Senate legislation might be approved. If we were required to clear such transactions, we would likely be precluded from using our noncash assets as collateral for hedging arrangements. This preclusion could have a material impact on our liquidity, particularly if the final legislation does not provide for the grandfathering of existing OTC derivatives. As a result, if applied to our OTC derivatives transactions, legislation that impairs the use of asset-backed transactions could significantly increase our costs of entering into OTC derivatives and/or could significantly limit our ability to enter into OTC derivatives and hedge our commodity and interest rate risks. We cannot predict whether or when final legislation will be enacted or whether the US House of Representatives bill exemptions will be included in any final legislation.
See “Financial Condition – Liquidity and Capital Resources” below for a discussion of the liquidity effects of the long-term hedging program. Also see additional discussion of risk below under Item 7A, “Quantitative and Qualitative Disclosures about Market Risk.”
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Competitive Retail Markets and Customer Retention
Competitive retail activity in Texas has resulted in some volatility in retail customer counts. Total retail customer counts decreased less than 1% in 2007, rose 2% in 2008 and declined 3% in 2009. In responding to the competitive landscape in the ERCOT marketplace, we are focusing on the following key initiatives:
| • | Maintaining competitive pricing initiatives as evidenced by price reductions on most residential service plans in 2008 and 2009, in addition to the 15% cumulative price reduction in 2007 applicable to residential customers under qualifying service plans; |
| • | Profitably growing the retail customer base by actively competing for new and existing customers in areas in Texas open to competition. The customer retention strategy remains focused on continuing to implement initiatives to deliver world-class customer service and improve the overall customer experience; |
| • | Establishing TXU Energy as the most innovative retailer in the Texas market by continuing to develop tailored product offerings to meet customer needs. TXU Energy plans to invest $100 million over the five-year period beginning in 2008 (including $20 million invested through 2009) in retail initiatives aimed at helping consumers conserve energy and other demand-side management initiatives that are intended to moderate consumption and reduce peak demand for electricity, and |
| • | Focusing business market initiatives largely on programs targeted to retain the existing highest-value customers and to recapture customers who have switched REPs. Initiatives include maintaining and continuously refining a disciplined contracting and pricing approach and economic segmentation of the business market to enhance targeted sales and marketing efforts and to more effectively deploy the direct-sales force. Tactical programs put into place include improved customer service, aided by a new customer management system implemented in 2009, the successful operation of which is critical to customer satisfaction, new product price/service offerings and a multichannel approach for the small business market. |
Volatile Energy Prices and Regulatory Risk
Natural gas prices rose to unprecedented levels in the latter part of 2005, reflecting a world-wide increase in energy prices compounded by hurricane-related infrastructure damage. The related rise in electricity prices elevated public awareness of energy costs and dampened customer demand. Natural gas prices remain subject to events that create price volatility, and while not reaching 2005 levels, forward natural gas prices rose substantially in 2007 and part of 2008 before falling in the second half of 2008 and continuing to fall through most of 2009. Sustained high energy prices and/or ongoing price volatility also creates a risk for regulatory and/or legislative intervention with the mechanisms that govern the competitive wholesale and retail markets in ERCOT. We believe that competitive markets result in a broad range of innovative pricing and service alternatives to consumers and ultimately the most efficient use of resources and regulatory entities should continue to take actions that encourage competition in the industry. Regulatory and/or legislative intervention could disrupt the relationship between natural gas prices and electricity prices, which could impact the results of our long-term hedging strategy and our results of operations.
New and Changing Environmental Regulations
We are subject to various environmental laws and regulations related to SO2, NOx and mercury emissions as well as other environmental contaminants that impact air and water quality. We are in compliance with all current laws and regulations, but regulatory authorities continue to evaluate existing requirements and consider proposals for changes. We continue to closely monitor any potential legislative and regulatory changes pertaining to global climate change. In view of the fact that a substantial portion of our generation portfolio consists of lignite/coal-fueled generation facilities, our financial condition or results of operations could be materially adversely affected by the enactment of any legislation, regulation or judicial action that mandates a reduction in GHG emissions or that imposes financial penalties, costs or taxes on entities that produce GHG emissions. For example, federal, state or regional legislation or regulation addressing global climate change could result in us either incurring increased material costs to reduce our GHG emissions or to procure emission allowances or credits to comply with a mandatory cap-and-trade emissions reduction program or incurring increased taxes, which could be material, due to the imposition of a carbon tax. See further discussion under Items 1 and 2, “Business and Properties – Environmental Regulations and Related Considerations.”
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Exposures Related to Nuclear Asset Outages
Our nuclear assets are comprised of two generation units at Comanche Peak, each with an installed nameplate capacity of 1,150 MW. The Comanche Peak plant represents approximately 13% of our total generation capacity. The nuclear generation units represent our lowest marginal cost source of electricity. Assuming both nuclear generation units experienced an outage, the unfavorable impact to pretax earnings is estimated to be approximately $2 million per day before consideration of any insurance proceeds. Also see discussion of nuclear facilities insurance in Note 13 to Financial Statements.
The inherent complexities and related regulations associated with operating nuclear generation facilities result in environmental, regulatory and financial risks. The operation of nuclear generation facilities is complex and subject to continuing review and regulation by the NRC, covering, among other things, operations, maintenance, emergency planning, security, and environmental and safety protection. The NRC may implement changes in regulations that result in increased capital or operating costs, and it may require extended outages, modify, suspend or revoke operating licenses and impose fines for failure to comply with its existing regulations and the provisions of the Atomic Energy Act. In addition, an unplanned outage at another nuclear generation facility could result in the NRC taking action to shut down the Comanche Peak plant as a precautionary measure.
The Comanche Peak plant has not experienced an extended unplanned outage, and management continues to focus on the safe, reliable and efficient operations at the plant.
Other Matters
See Note 13 to Financial Statements for discussion of litigation related to our new lignite-fueled generation facility construction program and “Regulation and Rates” for discussion of ERCOT’s planned implementation of a nodal market.
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APPLICATION OF CRITICAL ACCOUNTING POLICIES
Our significant accounting policies are discussed in Note 1 to Financial Statements. We follow accounting principles generally accepted in the US. Application of these accounting policies in the preparation of our consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and revenues and expenses during the periods covered. The following is a summary of certain critical accounting policies that are impacted by judgments and uncertainties and under which different amounts might be reported using different assumptions or estimation methodologies.
Purchase Accounting
In 2007, the Merger was accounted for under purchase accounting, whereby the purchase price of the transaction was allocated to our identifiable assets acquired and liabilities assumed based upon their fair values. The estimates of the fair values recorded were determined based on the principles in accounting standards related to the determination of fair value (see Note 16 to 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 Notes 2 and 3 to Financial Statements for details of the purchase price allocation and intangible assets recorded, respectively.
With respect to Oncor, the realization of its assets and settlement of its liabilities are largely subject to cost-based regulatory rate-setting processes. Accordingly, the historical carrying values of a majority of Oncor's assets and liabilities are deemed to represent fair values. See discussion in Note 25 to Financial Statements regarding adjustments to the carrying values of Oncor’s regulatory asset and related long-term debt.
The excess of the purchase price over the estimated fair values of the net assets acquired was recorded as goodwill. The goodwill amount recorded upon finalization of purchase accounting totaled $23.2 billion. Management believes the drivers of the goodwill amount included the incremental value of the future cash flow potential of the baseload generation facilities, including facilities under construction, over the values assigned to those assets under purchase accounting rules, considering the market-pricing mechanisms and growth potential in the ERCOT market, as well as the value derived from the scale of the retail business. Management also believes that the goodwill reflected the value of the relatively stable, long-lived cash flows of the regulated business, considering the constructive regulatory environment and market growth potential. In accordance with accounting guidance related to goodwill and other intangible assets, goodwill is not amortized to net income, but is required to be tested for impairment at least annually. This guidance requires that goodwill be assigned to “reporting units,” which management has determined to be the Competitive Electric segment and the Regulated Delivery segment, which are almost entirely comprised of TCEH and Oncor, respectively. The assignment of goodwill was based on the relative estimated enterprise values of the operations as of the date of the Merger using discounted cash flow methodologies. Goodwill amounts assigned totaled $18.3 billion to the Competitive Electric segment and $4.9 billion to the Regulated Delivery segment. None of this goodwill balance is being deducted for tax purposes.
In the first quarter of 2009 and fourth quarter of 2008, we recorded goodwill impairment charges totaling $8.950 billion. The $90 million charge in the first quarter of 2009 resulted from the completion of the previously estimated fair value calculations supporting the initial $8.860 billion goodwill impairment charge that was recorded in the fourth quarter of 2008. See discussion immediately below under “Impairment of Assets.”
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Impairment of Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist, in accordance with accounting standards related to impairment or disposal of long-lived assets, whenever events or changes in circumstances indicate that their carrying amount may not be recoverable. One of those indications is a current expectation that “more likely than not” a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life (as was the case for the natural gas-fueled generation assets discussed below). For our baseload generation assets, another possible indication would be an expected long-term decline in natural gas prices and/or market heat rates. The determination of the existence of these and other indications of impairment involves judgments that are subjective in nature and may require the use of estimates in forecasting future results and cash flows related to an asset or group of assets. Further, the unique nature of our property, plant and equipment, which includes a fleet of generation assets with a diverse fuel mix and individual plants that have varying production or output rates, requires the use of significant judgments in determining the existence of impairment indications and the grouping of assets for impairment testing.
Goodwill and intangible assets with indefinite useful lives are required to be tested for impairment at least annually or whenever events or changes in circumstances indicate an impairment may exist, such as the possible impairments to long-lived assets discussed above. Effective with 2009 testing, we changed the annual test date for goodwill and intangible assets with indefinite useful lives from October 1 to December 1. Management determined the new annual goodwill test date is preferable because of efficiencies gained by aligning the test with our annual budget and five-year plan processes in the fourth quarter. The change in the annual test date did not delay, accelerate or avoid an impairment charge, and retrospective application of this change in accounting principle did not affect previously reported results. As required by accounting guidance related to goodwill and other intangible assets, we have allocated goodwill to our reporting units, which are our two segments: Competitive Electric and Regulated Delivery, and goodwill impairment testing is performed at the reporting unit level. Under this goodwill impairment analysis, if at the assessment date, a reporting unit’s carrying value exceeds its estimated fair value (enterprise value), the estimated enterprise value of the reporting unit is compared to the estimated fair values of the reporting unit’s operating assets (including identifiable intangible assets) and liabilities at the assessment date, and the resultant implied goodwill amount is then compared to the recorded goodwill amount. Any excess of the recorded goodwill amount over the implied goodwill amount is written off as an impairment charge.
The determination of enterprise value involves a number of assumptions and estimates. We use a combination of three fair value inputs to estimate enterprise values of our reporting units: internal discounted cash flow analyses (income approach), comparable company equity values and any recent pending and/or completed relevant transactions. The income approach involves estimates of future performance that reflect assumptions regarding, among other things, forward natural gas and electricity prices, market heat rates, generation plant performance and retail sales volume trends. Another key variable in the income approach is the discount rate, or weighted average cost of capital. The determination of the discount rate takes into consideration the capital structure, debt ratings and current debt yields of comparable companies as well as an estimate of return on equity that reflects historical market returns and current market volatility for the industry. Enterprise value estimates based on comparable company equity values involve using trading multiples of EBITDA of those selected companies to derive appropriate multiples to apply to the EBITDA of the reporting units. This approach requires an estimate, using historical acquisition data, of an appropriate control premium to apply to the reporting unit values calculated from such multiples. Critical judgments include the selection of comparable companies and the weighting of the three value inputs in developing the best estimate of enterprise value.
The 2009 annual impairment testing performed as of October 1, and December 1, 2009 for goodwill and intangible assets with indefinite useful lives in accordance with accounting guidance for a change in annual impairment testing dates resulted in no impairment (see discussion in Note 1 to Financial Statements regarding change in the annual impairment test date from October 1 to December 1). The goodwill testing determined that the estimated fair value (enterprise value) of the Regulated Delivery segment exceeded its carrying value by approximately 10% resulting in no additional testing being required and no impairment for the segment. Key assumptions in the valuation of the regulated business include discount rates, growth of the rate base and return on equity allowed by the regulatory authority. Cash flows of the regulated business are relatively stable and more predictable than the competitive business. The Competitive Electric segment carrying value exceeded its estimated enterprise value (by less than 10%), so the estimated enterprise value of the segment was compared to the estimated fair values of its operating assets and liabilities. This additional testing indicated that the implied goodwill amount exceeded the recorded goodwill amount, and thus no goodwill impairment was recorded. The estimated enterprise value of the Competitive Electric segment reflects the impact of the decline in forward natural gas prices on wholesale electricity prices. Because lower wholesale electricity prices also result in lower fair values of our generation assets, calculated implied goodwill was sufficient to support the recorded goodwill amount. Key variables in the tests included forward natural gas prices, electricity prices, market heat rates and discount rates, assumptions regarding each of which could have a significant effect on valuations. Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.
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See Note 3 to Financial Statements for a discussion of the goodwill impairment charges of $8.860 billion and $90 million (not deductible for income tax purposes) recorded in the fourth quarter of 2008 and first quarter of 2009, respectively. The total $8.950 billion impairment charge represented approximately 39% of the goodwill balance resulting from purchase accounting for the Merger and reflected a decline of approximately 20% in the estimated value of EFH Corp. at year-end 2008 from the indicated value at the October 2007 Merger date. The impairment primarily arose from the dislocation in the capital markets that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies in the second half of 2008. Also see Note 3 to Financial Statements for discussion of the impairment charge of $481 million ($310 million after-tax) related to the trade name intangible asset also recorded in the fourth quarter of 2008. The estimated fair value of this intangible asset is based on an assumed royalty methodology.
In the fourth quarter of 2008, we recorded an impairment charge of $229 million ($147 million after-tax) related to our natural gas-fueled generation facilities. The natural gas-fueled generation units are generally operated to meet peak demands for electricity, and the facilities tested for impairment as an asset group. See Note 5 to 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.
In 2007, we recorded a net charge totaling $757 million ($492 million after-tax) (substantially all of which was in the Predecessor period) in connection with the 2007 suspension and subsequent cancellation of the development of eight coal-fueled generation units. This decision and subsequent terminations of equipment orders required an evaluation and substantial judgments regarding the recoverability of recorded assets associated with the development program. In determining the net charges recorded, we applied accounting rules for impairment of long-lived assets under guidance related to impairment or disposal of long-lived assets and for exit activities under guidance related to accounting for costs associated with exit or disposal activities. See Note 4 to Financial Statements for additional discussion.
Derivative Instruments and Mark-to-Market Accounting
We enter into contracts for the purchase and sale of energy-related commodities, and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. Under accounting standards related to derivative instruments and hedging activities, these instruments are subject to mark-to-market accounting, and the determination of market values for these instruments is based on numerous assumptions and estimation techniques.
Mark-to-market accounting recognizes changes in the fair value of derivative instruments in the financial statements as market prices change. Such changes in fair value are accounted for as unrealized mark-to-market gains and losses in net income with an offset to derivative assets and liabilities. The availability of quoted market prices in energy markets is dependent on the type of commodity (e.g., natural gas, electricity, etc.), time period specified and delivery point. In computing fair value for derivatives, each forward pricing curve is separated into liquid and illiquid periods. The liquid period varies by delivery point and commodity. Generally, the liquid period is supported by exchange markets, broker quotes and frequent trading activity. For illiquid periods, fair value is estimated based on forward price curves developed using modeling techniques that take into account available market information and other inputs that might not be readily observable in the market. We adopted new accounting standards related to the determination of fair value concurrent with the Merger and estimate fair value as described in Note 16 to Financial Statements and discussed under “Fair Value Measurements” below.
Accounting standards related to derivative instruments and hedging activities allow for “normal” purchase or sale elections and hedge accounting designations, which generally eliminate or defer the requirement for mark-to-market recognition in net income and thus reduce the volatility of net income that can result from fluctuations in fair values. These elections and designations are intended to match the accounting recognition of the contract's financial performance to that of the transaction the contract is intended to hedge. “Normal” purchases and sales are contracts that provide for physical delivery of quantities expected to be used or sold over a reasonable period in the normal course of business and are not subject to mark-to-market accounting.
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Under hedge accounting, changes in fair value of instruments designated as cash flow hedges are recorded in other comprehensive income with an offset to derivative assets and liabilities to the extent the change in value is effective; that is, it mirrors the offsetting change in fair value of the forecasted hedged transaction. Changes in value that represent ineffectiveness of the hedge are recognized in net income immediately, and the effective portion of changes in fair value initially recorded in other comprehensive income are recognized in net income in the period that the hedged transactions are recognized. Although as of December 31, 2009, we do not have any derivatives designated as cash flow or fair value hedges, we continually assess our hedge elections and could designate positions as cash flow hedges in the future. In March 2007, the instruments making up a significant portion of the long-term hedging program that were previously designated as cash flow hedges were dedesignated as allowed under accounting standards related to derivative instruments and hedging activities, and subsequent changes in their fair value are being marked-to-market in net income. In addition, in August 2008, interest rate swap transactions in effect at that time were dedesignated as cash flow hedges in accordance with accounting standards, and subsequent changes in their fair value are being marked-to-market in net income. See further discussion of the long-term hedging program and interest rate swap transactions above under “Business – Significant Activities and Events.”
The following tables provide the effects on both net income and other comprehensive income of mark-to-market accounting for those derivative instruments that we have determined to be subject to fair value measurement under accounting standards related to derivative instruments and hedging activities.
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Amounts recognized in net income (after-tax): | ||||||||||||||||||
Unrealized net gains (losses) on positions marked-to-market in net income (a) | $ | 1,573 | $ | 518 | $ | (955 | ) | $ | (492 | ) | ||||||||
Unrealized net (gains) losses representing reversals of previously recognized fair values of positions settled in the period (a) | (333 | ) | 25 | (56 | ) | (36 | ) | |||||||||||
Unrealized ineffectiveness net gains (losses) on positions accounted for as cash flow hedges | — | (3 | ) | $ | — | 74 | ||||||||||||
Reversals of previously recognized unrealized net (gains) losses related to cash flow hedge positions settled in the period | 1 | — | — | (15 | ) | |||||||||||||
Total | $ | 1,241 | $ | 540 | $ | (1,011 | ) | $ | (469 | ) | ||||||||
Amounts recognized in other comprehensive income (after-tax): | ||||||||||||||||||
Net losses in fair value of positions accounted for as cash flow hedges | $ | (20 | ) | $ | (183 | ) | $ | (177 | ) | $ | (288 | ) | ||||||
Net (gains) losses on cash flow hedge positions recognized in net income to offset hedged transactions | 130 | 122 | — | (89 | ) | |||||||||||||
Total | $ | 110 | $ | (61 | ) | $ | (177 | ) | $ | (377 | ) | |||||||
| (a) | Amounts for 2009 and 2008 include $788 million and $1.503 billion in net after-tax gains related to commodity positions, respectively, and $452 million in net after-tax gains and $960 million in net after-tax losses related to interest rate swaps, respectively. Prior period amounts are essentially all related to commodity positions. |
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The effect of mark-to-market and hedge accounting for derivatives on the balance sheet is as follows:
| Successor | ||||||||
| December 31, 2009 | December 31, 2008 | |||||||
Net commodity contract asset (a) | $ | 1,714 | $ | 466 | ||||
Net derivative liability related to interest rate hedges | (1,242 | ) | (1,944 | ) | ||||
Net accumulated other comprehensive loss included in shareholders’ equity (amounts after tax) | $ | (128 | ) | $ | (238 | ) | ||
(a) 2009 amount includes $4 million in net derivative liabilities and 2008 amount includes $7 million in net derivative assets related to cash flow hedge positions not marked-to-market in net income. |
| |||||||
Fair Value Measurements
In addition to purchase accounting, we apply fair value accounting on a recurring basis to certain assets and financial instruments under the fair value hierarchy established in accounting standards related to the determination of fair value. We utilize several valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These techniques include, but are not limited to, the use of broker quotes and statistical relationships between different price curves and are intended to maximize the use of observable inputs and minimize the use of unobservable inputs. In applying the market approach, we use a mid-market valuation convention (the mid-point between bid and ask prices) as a practical expedient.
Level 1 and Level 2 assets and liabilities consist primarily of commodity-related contracts for natural gas and electricity derivative instruments entered into for hedging purposes, securities associated with the nuclear decommissioning trust, and interest rate swaps intended to fix and/or lower interest payments on long-term debt. Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. Level 2 valuations are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences. Level 2 inputs include:
| • | quoted prices for similar assets or liabilities in active markets; |
| • | quoted prices for identical or similar assets or liabilities in markets that are not active; |
| • | inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals, and |
| • | inputs that are derived principally from or corroborated by observable market data by correlation or other means. |
Examples of Level 2 valuation inputs utilized include over-the-counter broker quotes and quoted prices for similar assets or liabilities that are corroborated by correlation or through statistical relationships between different price curves. For example, certain physical power derivatives are executed for a particular location at specific time periods that might not have active markets; however, an active market might exist for such derivatives for a different time period at the same location. We utilize correlation techniques to compare prices for inputs at both time periods to provide a basis to value the non-active derivative. (See Note 16 to Financial Statements for additional discussion of how broker quotes are utilized.)
Level 3 assets and liabilities consist primarily of more complex long-term power purchases and sales agreements, including longer-term wind and other power purchase and sales contracts and certain natural gas positions (collars) in the long-term hedging program. Level 3 assets and liabilities are valued using significant unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets and liabilities. We use the most meaningful information available from the market, combined with our own internally developed valuation methodologies, to develop our best estimate of fair value. The determination of fair value for Level 3 assets and liabilities requires significant management judgment and estimation.
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Valuations of Level 3 assets and liabilities are sensitive to the assumptions used for the significant inputs. Where market data is available, the inputs used for valuation reflect that information as of our valuation date. In periods of extreme volatility, lessened liquidity or in illiquid markets, there may be more variability in market pricing or a lack of market data to use in the valuation process. An illiquid market is one in which little or no observable activity has occurred or one that lacks willing buyers. Valuation risk is mitigated through the performance of stress testing of the significant inputs to understand the impact that varying assumptions may have on the valuation and other review processes performed to ensure appropriate valuation.
As part of our valuation of assets subject to fair value accounting, counterparty credit risk is taken into consideration by measuring the extent of netting arrangements in place with the counterparty along with credit enhancements and the estimated credit rating of the counterparty. Our valuation of liabilities subject to fair value accounting takes into consideration the market’s view of our credit risk along with the existence of netting arrangements in place with the counterparty and credit enhancements posted by us. We consider the credit risk adjustment to be a Level 3 input since judgment is used to assign credit ratings, recovery rate factors and default rate factors.
Level 3 assets totaled $350 million and $283 million at December 31, 2009 and 2008, respectively, and represented approximately 8% and 7%, respectively, of the assets measured at fair value, or less than 1% of total assets. Level 3 liabilities totaled $269 million and $355 million at December 31, 2009 and 2008, respectively, and represented approximately 8% and 7%, respectively, of the liabilities measured at fair value, or less than 1% of total liabilities.
Valuations of several of our Level 3 assets and liabilities are based on long-dated price curves for electricity that are developed internally. Additionally, Level 3 assets and liabilities are sensitive to changes in discount rates, option-pricing model inputs such as volatility factors and credit risk adjustments. As of December 31, 2009, a $5.00 per MWh change in electricity price assumptions across unobservable inputs, primarily related to the outer years in our long-dated pricing model (years that are not market observable) would cause an approximate $72 million change in net Level 3 assets. A 10% change in diesel fuel price assumptions across unobservable inputs would cause an approximate $11 million change in net Level 3 assets. In addition, we have derivative contracts that are valued based on option-pricing models with unobservable inputs. A 10% increase in volatility and correlation related to these contracts would cause an approximate $5 million change in net Level 3 assets. See Note 16 to 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, 2009.
Revenue Recognition
Our revenue includes an estimate for unbilled revenue that represents estimated daily kWh consumption after the meter read date to the end of the period multiplied by the applicable billing rates. Estimated daily kWh usage is derived using historical kWh usage information adjusted for weather and other measurable factors affecting consumption. Calculations of unbilled revenues during certain interim periods are generally subject to more estimation variability because of seasonal changes in demand. Accrued unbilled revenues totaled $546 million, $505 million and $477 million at December 31, 2009, 2008 and 2007, respectively.
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Accounting for Contingencies
Our financial results may be affected by judgments and estimates related to loss contingencies. A significant contingency that we account for is the loss associated with uncollectible trade accounts receivable. The determination of such bad debt expense is based on factors such as historical write-off experience, aging of accounts receivable balances, changes in operating practices, regulatory rulings, general economic conditions, effects of hurricanes and other natural disasters and customers' behaviors. Changes in customer count and mix due to competitive activity and seasonal variations in amounts billed add to the complexity of the estimation process. Historical results alone are not always indicative of future results, causing management to consider potential changes in customer behavior and make judgments about the collectability of accounts receivable. Bad debt expense totaled $113 million, $81 million, $13 million and $46 million for the years ended December 31, 2009 and 2008, the period from October 11, 2007 to December 31, 2007 and the period from January 1, 2007 to October 10, 2007, respectively. The increase in bad debt in 2009 reflected higher delinquencies due to delays in final bills and disconnects resulting from a customer billing and information management system conversion, customer losses and general economic conditions. Amounts in 2008 reflected competitive customer acquisitions in south Texas and the effects of Hurricane Ike. See Note 10 to Financial Statements regarding a reserve recorded in 2008 for amounts due from subsidiaries of Lehman.
Litigation contingencies also may require significant judgment in estimating amounts to accrue. We accrue liabilities for litigation contingencies when such liabilities are considered probable of occurring and the amount is reasonably estimable. No significant amounts have been accrued for such contingencies during the three-year period ended December 31, 2009. See Item 3, “Legal Proceedings” for discussion of major litigation.
Accounting for Income Taxes
Our income tax expense and related balance sheet amounts involve significant management estimates and judgments. Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, involve judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. In assessing the likelihood of realization of deferred tax assets, management considers estimates of the amount and character of future taxable income. Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, our forecasted financial condition and results of operations in future periods, as well as final review of filed tax returns by taxing authorities. Our income tax returns are regularly subject to examination by applicable tax authorities. In management’s opinion, the liability recorded pursuant to income tax accounting guidance related to uncertain tax positions reflects future taxes that may be owed as a result of any examination.
As discussed in Note 8 to Financial Statements, in January 2007 we adopted new accounting standards that provide interpretive guidance for accounting for uncertain tax positions. See Notes 1 and 9 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 23 to 60 years for the lignite/coal- and nuclear-fueled generation units. See Note 1 to Financial Statements under “Property, Plant and Equipment” for discussion of the change from composite to asset-by-asset depreciation effective with the Merger.
As a result of cost-based regulatory rate-setting processes, the book value of the majority of Oncor’s assets and liabilities effectively represent fair value, and no adjustments to those regulated assets or liabilities were recorded as part of purchase accounting for the Merger. Depreciation expense for such assets totaled $394 million, $330 million and $298 million in 2009, 2008 and 2007, or 3.1% of carrying value in 2009 and 2.8% in 2008 and 2007.
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Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 3 to Financial Statements for additional information.
Regulatory Assets
The financial statements at December 31, 2009 and 2008, reflect total regulatory assets of $2.170 billion and $2.071 billion, respectively. These amounts include $759 million and $865 million, respectively, of generation-related regulatory assets recoverable by securitization (transition) bonds as discussed immediately below. Rate regulation is premised on the full recovery of prudently incurred costs and a reasonable rate of return on invested capital. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. (See “Oncor’s Regulatory Assets and Liabilities” in Note 25 to Financial Statements.)
Generation-related regulatory asset stranded costs arising prior to the 1999 Restructuring Legislation became subject to recovery through issuance of $1.3 billion principal amount of transition bonds in accordance with a regulatory financing order. The carrying value of the regulatory asset upon final issuance of the bonds in 2004 represented the projected future cash flows to be recovered from REPs by Oncor through revenues as a transition charge to service the principal and fixed rate interest on the bonds. The regulatory asset is being amortized to expense in an amount equal to the transition charge revenues being recognized. As discussed in Note 2 to Financial Statements, the regulatory asset and related transition bonds were adjusted to fair value on the date of the Merger in accordance with purchase accounting rules.
Other regulatory assets that we believe are probable of recovery, but are subject to review and possible disallowance, totaled $148 million at December 31, 2009. These amounts consist primarily of storm-related service recovery costs and employee retirement costs.
In August 2009, the PUCT issued a final order in Oncor’s first rate review in more than seven years. As discussed in Note 25 to Financial Statements, the order resulted in a write off of regulatory assets of $25 million.
Defined Benefit Pension Plans and OPEB Plans
We provide pension benefits based on either a traditional defined benefit formula or a cash balance formula and also provide certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from our company. Reported costs of providing noncontributory defined pension benefits and OPEB are dependent upon numerous factors, assumptions and estimates.
PURA provides for the recovery by Oncor of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility. These costs are associated with Oncor's active and retired employees, as well as active and retired personnel engaged in other EFH Corp. activities related to their service prior to the deregulation and disaggregation of our business effective January 1, 2002. Oncor is authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs reflected in Oncor's approved (by the PUCT) billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Accordingly, Oncor defers (principally as a regulatory asset or property) additional pension and OPEB costs consistent with PURA. Amounts deferred are ultimately subject to regulatory approval.
Benefit costs are impacted by actual employee demographics (including but not limited to age, compensation levels and years of accredited service), the level of contributions made to retiree plans, expected and actual earnings on plan assets and the discount rates used in determining the projected benefit obligation. Changes made to the provisions of the plans may also impact current and future benefit costs. Fluctuations in actual equity market returns as well as changes in general interest rates may result in increased or decreased benefit costs in future periods.
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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:
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | ||||||||||||||||||
| 2009 | 2008 | |||||||||||||||||||
Pension costs | $ | 44 | $ | 21 | $ | (1 | ) | $ | 34 | |||||||||||
OPEB costs | 70 | 58 | 11 | 49 | ||||||||||||||||
Total benefit costs | $ | 114 | $ | 79 | $ | 10 | $ | 83 | ||||||||||||
Less amounts deferred principally as a regulatory asset or property | (66 | ) | (42 | ) | (8 | ) | (43 | ) | ||||||||||||
Net amounts recognized as expense | $ | 48 | $ | 37 | $ | 2 | $ | 40 | ||||||||||||
Discount rate (a) | 6.90 | % | 6.55 | % | 6.45 | % | 5.90 | % | ||||||||||||
(a) Discount rate for OPEB was 6.85% in 2009. |
| |||||||||||||||||||
See Note 21 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 2009 Pension and OPEB Costs | |||
Discount rate – 1% increase | $ | (36 | ) | |
Discount rate – 1% decrease | $ | 44 | ||
Expected return on assets – 1% increase | $ | (22 | ) | |
Expected return on assets – 1% decrease | $ | 22 | ||
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PRESENTATION AND ANALYSIS OF RESULTS
The accompanying statements of consolidated income and cash flows for 2007 are presented for two periods: January 1, 2007 through October 10, 2007 (Predecessor) and October 11, 2007 through December 31, 2007 (Successor), which relate to the period before the Merger and the period after the Merger, respectively. Management's discussion and analysis of results of operations and cash flows has been prepared by comparing the results of operations and cash flows of the Successor for the year ended December 31, 2009 to those of the Successor for the year ended December 31, 2008, by comparing the results of operations and cash flows of the Successor for the three months ended December 31, 2008 to those of the Successor for the period October 11, 2007 through December 31, 2007 and by comparing the results of operations and cash flows of the Successor for the nine months ended September 30, 2008 to those of the Predecessor for the period January 1, 2007 through October 10, 2007. To facilitate the discussion, certain volumetric and statistical data for 2008 have been presented as of and for the nine months ended September 30, 2008 compared to the nine months ended September 30, 2007 and as of and for the three months ended December 31, 2008 compared to the three months ended December 31, 2007. Such volumetric and statistical data are measured and reported on a monthly, quarterly and annual basis.
RESULTS OF OPERATIONS
Consolidated Financial Results
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Three Months Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Nine Months Ended September 30, 2008 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||||||||
Operating revenues | $ | 9,546 | $ | 11,364 | $ | 2,364 | $ | 1,994 | $ | 9,001 | $ | 8,044 | ||||||||||||||
Fuel, purchased power costs and delivery fees | (2,878 | ) | (4,595 | ) | (728 | ) | (644 | ) | (3,867 | ) | (2,381 | ) | ||||||||||||||
Net gain (loss) from commodity hedging and trading activities | 1,736 | 2,184 | 2,432 | (1,492 | ) | (248 | ) | (554 | ) | |||||||||||||||||
Operating costs | (1,598 | ) | (1,503 | ) | (383 | ) | (306 | ) | (1,120 | ) | (1,107 | ) | ||||||||||||||
Depreciation and amortization | (1,754 | ) | (1,610 | ) | (393 | ) | (415 | ) | (1,217 | ) | (634 | ) | ||||||||||||||
Selling, general and administrative expenses | (1,068 | ) | (957 | ) | (245 | ) | (216 | ) | (712 | ) | (691 | ) | ||||||||||||||
Franchise and revenue-based taxes | (359 | ) | (363 | ) | (104 | ) | (93 | ) | (259 | ) | (282 | ) | ||||||||||||||
Impairment of goodwill | (90 | ) | (8,860 | ) | (8,860 | ) | — | — | — | |||||||||||||||||
Other income | 204 | 80 | 37 | 14 | 43 | 69 | ||||||||||||||||||||
Other deductions | (97 | ) | (1,301 | ) | (718 | ) | (61 | ) | (583 | ) | (841 | ) | ||||||||||||||
Interest income | 45 | 27 | 5 | 24 | 22 | 56 | ||||||||||||||||||||
Interest expense and related charges | (2,912 | ) | (4,935 | ) | (2,431 | ) | (839 | ) | (2,505 | ) | (671 | ) | ||||||||||||||
Income (loss) from continuing operations before income taxes | 775 | (10,469 | ) | (9,024 | ) | (2,034 | ) | (1,445 | ) | 1,008 | ||||||||||||||||
Income tax (expense) benefit | (367 | ) | 471 | 9 | 673 | 462 | (309 | ) | ||||||||||||||||||
Income (loss) from continuing operations | 408 | (9,998 | ) | (9,015 | ) | (1,361 | ) | (983 | ) | 699 | ||||||||||||||||
Income from discontinued operations, net of tax effect | — | — | — | 1 | — | 24 | ||||||||||||||||||||
Net income (loss) | 408 | (9,998 | ) | (9,015 | ) | (1,360 | ) | (983 | ) | 723 | ||||||||||||||||
Net (income) loss attributable to noncontrolling interests | (64 | ) | 160 | 160 | — | — | — | |||||||||||||||||||
Net income (loss) attributable to EFH Corp. | $ | 344 | $ | (9,838 | ) | $ | (8,855 | ) | $ | (1,360 | ) | $ | (983 | ) | $ | 723 | ||||||||||
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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. |
SG&A expenses increased $111 million, or 12%, to $1.068 billion in 2009.
| • | SG&A expenses in the Competitive Electric segment increased $59 million, or 9%, to $741 million. |
| • | SG&A expenses in the Regulated Delivery segment increased $30 million, or 18%, to $194 million. |
| • | Corporate and Other SG&A expenses increased $22 million, or 20%, to $133 million driven by higher transition costs associated with outsourced support services. |
See Note 3 to Financial Statements for discussion of the $90 million and $8.860 billion impairments of goodwill in 2009 and 2008, respectively.
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Other income totaled $204 million in 2009 and $80 million in 2008, including $39 million and $44 million, respectively, in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. The 2009 amount also included an $87 million debt extinguishment gain (see discussion of debt exchanges in Note 12 to 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 Notes 2 and 20 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 25 to Financial Statements under “Oncor’s Regulatory Assets and Liabilities.” 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 3 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 10 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 18 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 25 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.
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. |
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Consolidated Financial Results — Three Months Ended December 31, 2008 Compared to Successor Period From October 11, 2007 Through December 31, 2007
Reference is made to comparisons of results by business segment following the discussion of consolidated results. The business segment comparisons provide additional detail and quantification of items affecting financial results.
Operating revenues increased $370 million, or 19%, to $2.364 billion in 2008.
| • | Operating revenues in the Competitive Electric segment increased $308 million, or 18%, to $1.979 billion. |
| • | Operating revenues in the Regulated Delivery segment increased $80 million, or 15%, to $612 million. |
| • | Net intercompany sales eliminations increased $18 million, reflecting Oncor’s higher distribution revenues from REP subsidiaries of TCEH. |
Fuel, purchased power costs and delivery fees increased $84 million, or 13%, to $728 million in 2008. See discussion below in the analysis of Competitive Electric segment results of operations.
Net gain (loss) from commodity hedging and trading activities totaled $2.432 billion in net gains in 2008 compared to $1.492 billion in net losses in 2007. Results in 2008 included $2.586 billion in unrealized mark-to-market net gains, and results in 2007 included $1.556 billion in unrealized mark-to-market net losses driven by the effect of changes in forward market prices of natural gas on the value of positions in the long-term hedging program. See discussion below in the analysis of Competitive Electric segment results of operations.
Operating costs increased $77 million, or 25%, to $383 million in 2008.
| • | Operating costs in the Competitive Electric segment increased $53 million, or 43%, to $177 million. |
| • | Operating costs in the Regulated Delivery segment increased $26 million, or 14%, to $208 million. |
Depreciation and amortization decreased $22 million, or 5%, to $393 million in 2008.
| • | Depreciation and amortization in the Competitive Electric segment decreased $50 million, or 16%, to $265 million. |
| • | Depreciation and amortization in the Regulated Delivery segment increased $26 million, or 27%, to $122 million. |
SG&A expenses increased $29 million, or 13%, to $245 million in 2008.
| • | SG&A expenses in the Competitive Electric segment increased $29 million, or 19%, to $183 million. |
| • | SG&A expenses in the Regulated Delivery segment decreased $7 million, or 16%, to $38 million. |
| • | Corporate and Other SG&A expenses increased $7 million, or 41%, to $24 million due primarily to incentive compensation and benefits expenses. |
See Note 3 to Financial Statements for discussion of the $8.860 billion goodwill impairment charge recorded in the fourth quarter of 2008.
Other income totaled $37 million in 2008 and $14 million in 2007, including $11 million and $10 million, respectively, in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. The 2008 amount also included a $21 million net insurance recovery for damage to certain mining equipment. Other deductions totaled $718 million in 2008 and $61 million in 2007. The 2008 amount included impairment charges of $481 million related to trade name intangible assets and $229 million related to the natural gas-fueled generation fleet. The 2007 amount included $51 million of professional fees incurred related to the Merger. See Note 10 to Financial Statements for details of other income and deductions.
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Interest expense and related charges increased $1.592 billion to $2.431 billion in 2008. The increase in interest expense and related charges was partially due to $27 million in expense and charges attributable to the ten fewer days in the 2007 period. The increase reflects increased rates, which includes an unrealized mark-to-market net loss on interest rate swaps of $1.512 billion, and higher average borrowings, partially offset by increased capitalized interest.
Income tax benefit totaled $9 million in 2008 compared to $673 million in 2007. The effective rate on a loss in 2008 was 5.5%, excluding the impact of the $8.860 billion goodwill impairment charge (this nondeductible charge distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion), and the effective rate on a loss in 2007 was 33.1%. The decrease in the rate was driven by an increase in interest accrued for uncertain tax positions.
Reflecting the goodwill impairment charge in 2008, after-tax results declined $7.655 billion to a loss of $9.015 billion in 2008.
| • | After-tax results in the Competitive Electric segment declined $6.822 billion to a loss of $8.067 billion in 2008. |
| • | After-tax results in the Regulated Delivery segment declined $858 million to a loss of $795 million in 2008. |
| • | Corporate and Other net expenses totaled $153 million in 2008 and $178 million in 2007. The amounts in 2008 and 2007 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The decrease of $25 million was driven by financial advisory, legal and other professional fees in 2007 directly related to the Merger. |
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Consolidated Financial Results — Nine Months Ended September 30, 2008 Compared to Predecessor Period From January 1, 2007 Through October 10, 2007
Reference is made to comparisons of results by business segment following the discussion of consolidated results. The business segment comparisons provide additional detail and quantification of items affecting financial results.
Operating revenues increased $957 million, or 12%, to $9.001 billion in 2008.
| • | Operating revenues in the Competitive Electric segment increased $925 million, or 13%, to $7.809 billion. |
| • | Operating revenues in the Regulated Delivery segment decreased $18 million, or less than 1%, to $1.969 billion. |
| • | Net intercompany sales eliminations decreased $50 million, reflecting lower sales by Oncor to REP subsidiaries of TCEH. |
Fuel, purchased power costs and delivery fees increased $1.486 billion, or 62%, to $3.867 billion in 2008. See discussion below in the analysis of Competitive Electric segment results of operations.
Net gain (loss) from commodity hedging and trading activities totaled $248 million in net losses in 2008 compared to $554 million in net losses in 2007. Results in 2008 included unrealized mark-to-market net losses totaling $305 million driven by the effect of higher forward market prices of natural gas on the value of hedge positions. See discussion below in the analysis of Competitive Electric segment results of operations.
Operating costs increased $13 million, or 1%, to $1.120 billion in 2008.
| • | Operating costs in the Competitive Electric segment increased $29 million, or 6%, to $500 million. |
| • | Operating costs in the Regulated Delivery segment decreased $17 million, or 3%, to $620 million. |
Depreciation and amortization increased $583 million, or 92%, to $1.217 billion in 2008.
| • | Depreciation and amortization in the Competitive Electric segment increased $574 million to $827 million. |
| • | Depreciation and amortization in the Regulated Delivery segment increased $4 million, or 1%, to $370 million. |
SG&A expenses increased $21 million, or 3%, to $712 million in 2008.
| • | SG&A expenses in the Competitive Electric segment increased $10 million, or 2%, to $499 million. |
| • | SG&A expenses in the Regulated Delivery segment decreased $13 million, or 9%, to $126 million. |
| • | Corporate and Other SG&A expenses increased $24 million, or 38%, to $87 million due primarily to Sponsor management fees of $26 million. |
Other income totaled $43 million in 2008 and $69 million in 2007. The 2008 amount included $33 million in accretion of the fair value adjustment to certain regulatory assets due to purchase accounting. The 2007 amount included $36 million of amortization of a deferred gain on sale of a business that was eliminated in purchase accounting. Other deductions totaled $583 million in 2008 and $841 million in 2007. The 2008 amount included impairment charges of $501 million related to NOx and SO2 environmental allowances intangible assets and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. The 2007 amount included net charges of $755 million related to the cancelled development of eight coal-fueled generation units (see Note 4 to Financial Statements). See Note 10 to Financial Statements for details of other income and deductions.
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Interest expense and related charges increased $1.834 billion to $2.505 billion in 2008 reflecting $1.397 billion due to higher average borrowings, driven by the Merger-related financings, and $614 million in higher average interest rates, including $54 million of amortization of debt fair value discount resulting from purchase accounting and a $36 million unrealized mark-to-market net gain related to interest rate swaps, partially offset by $150 million in increased capitalized interest. The increase was also net of $27 million in additional interest in the 2007 period attributable to the ten additional days in the period. See Note 25 to Financial Statements.
Income tax benefit totaled $462 million in 2008 compared to income tax expense of $309 million in 2007. The 2007 amount includes a deferred tax benefit of $70 million related to an amendment of the Texas margin tax by the Texas legislature. Excluding the effect of this 2007 item, the effective income tax rates were 32.0% on a loss in 2008 compared to 37.6% on income in 2007. (The deferred tax benefit in 2007 distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion.) The decrease in the effective tax rate is driven by the effect of interest accrued for uncertain tax positions.
After-tax results declined $1.706 billion to a loss of $983 million in 2008.
| • | After-tax results in the Competitive Electric segment declined $1.584 billion to a loss of $862 million in 2008. |
| • | Net income in the Regulated Delivery segment increased $44 million to $309 million in 2008. |
| • | Corporate and Other net expenses totaled $430 million in 2008 and $288 million in 2007. The amounts in 2008 and 2007 include recurring interest expense on outstanding debt and notes payable to subsidiaries, as well as corporate general and administrative expenses. The increase of $142 million reflected: |
| • | a $115 million increase in net interest expense, driven by issuance of Merger-related debt; |
| • | $23 million in lower other income reflecting the absence, due to purchase accounting, of amortization of a gain on the sale of a business; |
| • | a $38 million deferred tax benefit in 2007 related to the Texas margin tax, and |
| • | a $15 million increase in SG&A expense as discussed above. |
partially offset by:
| • | the write-off in 2007 of $25 million in previously deferred costs related to anticipated strategic transactions (including expected financings) that were no longer expected to be completed as a result of the Merger, and |
| • | $25 million in financial advisory, legal and other professional fees in 2007 related to the Merger. |
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Competitive Electric Segment
The following tables present financial operating results of the Competitive Electric segment for the Successor periods of the years ended December 31, 2009 and 2008, the three months ended December 31, 2008, the period from October 11, 2007 through December 31, 2007 and the nine months ended September 30, 2008, and for the Predecessor period from January 1, 2007 through October 10, 2007. Volumetric and other statistical data have been presented as of and for the Successor periods of the years ended December 31, 2009 and 2008, the three months ended December 31, 2008 and 2007 and the nine months ended December 31, 2008, and for the Predecessor period for the nine months ended September 30, 2007.
Financial Results
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Three Months Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Nine Months Ended September 30, 2008 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||||||||
Operating revenues | $ | 7,911 | $ | 9,787 | $ | 1,979 | $ | 1,671 | $ | 7,809 | $ | 6,884 | ||||||||||||||
Fuel, purchased power costs and delivery fees | (3,934 | ) | (5,600 | ) | (954 | ) | (852 | ) | (4,646 | ) | (3,209 | ) | ||||||||||||||
Net gain (loss) from commodity hedging and trading activities | 1,736 | 2,184 | 2,432 | (1,492 | ) | (248 | ) | (554 | ) | |||||||||||||||||
Operating costs | (693 | ) | (677 | ) | (177 | ) | (124 | ) | (500 | ) | (471 | ) | ||||||||||||||
Depreciation and amortization | (1,172 | ) | (1,092 | ) | (265 | ) | (315 | ) | (827 | ) | (253 | ) | ||||||||||||||
Selling, general and administrative expenses | (741 | ) | (682 | ) | (183 | ) | (154 | ) | (499 | ) | (489 | ) | ||||||||||||||
Franchise and revenue-based taxes | (108 | ) | (110 | ) | (36 | ) | (30 | ) | (74 | ) | (81 | ) | ||||||||||||||
Impairment of goodwill | (70 | ) | (8,000 | ) | (8,000 | ) | — | — | — | |||||||||||||||||
Other income | 59 | 34 | 26 | 2 | 8 | 22 | ||||||||||||||||||||
Other deductions | (68 | ) | (1,274 | ) | (715 | ) | (8 | ) | (559 | ) | (735 | ) | ||||||||||||||
Interest income | 64 | 61 | 15 | 10 | 46 | 271 | ||||||||||||||||||||
Interest expense and related charges | (1,946 | ) | (4,010 | ) | (2,187 | ) | (609 | ) | (1,824 | ) | (357 | ) | ||||||||||||||
Income (loss) before income taxes | 1,038 | (9,379 | ) | (8,065 | ) | (1,901 | ) | (1,314 | ) | 1,028 | ||||||||||||||||
Income tax (expense) benefit | (407 | ) | 450 | (2 | ) | 656 | 452 | (306 | ) | |||||||||||||||||
Net income (loss) | $ | 631 | $ | (8,929 | ) | $ | (8,067 | ) | $ | (1,245 | ) | $ | (862 | ) | $ | 722 | ||||||||||
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Competitive Electric Segment
Sales Volume and Customer Count Data
| Successor | Successor | Predecessor | ||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Three Months Ended December 31, 2008 | Three Months Ended December 31, 2007 | Nine Months Ended September 30, 2008 | Nine Months Ended September 30, 2007 | |||||||||||||
Sales volumes: | ||||||||||||||||||
Retail electricity sales volumes – (GWh): | ||||||||||||||||||
Residential | 28,046 | 28,135 | 5,982 | 5,967 | 22,153 | 21,256 | ||||||||||||
Small business (a) | 7,962 | 7,363 | 1,561 | 1,622 | 5,802 | 5,861 | ||||||||||||
Large business and other customers | 14,573 | 13,945 | 2,994 | 3,591 | 10,951 | 10,946 | ||||||||||||
Total retail electricity | 50,581 | 49,443 | 10,537 | 11,180 | 38,906 | 38,063 | ||||||||||||
Wholesale electricity sales volumes | 43,259 | 47,270 | 11,741 | 11,198 | 35,529 | 27,914 | ||||||||||||
Net sales (purchases) of balancing electricity to/from ERCOT | (939 | ) | (527 | ) | 808 | 47 | (1,335 | ) | 622 | |||||||||
Total sales volumes | 92,901 | 96,186 | 23,086 | 22,425 | 73,100 | 66,599 | ||||||||||||
Average volume (kWh) per residential customer (b) | 14,855 | 14,780 | 3,101 | 3,197 | 11,767 | 11,399 | ||||||||||||
Weather (North Texas average) – percent of normal (c): | ||||||||||||||||||
Cooling degree days | 98.9 | % | 108.5 | % | 101.3 | % | 171.8 | % | 109.0 | % | 94.2 | % | ||||||
Heating degree days | 99.9 | % | 92.5 | % | 90.7 | % | 89.7 | % | 93.7 | % | 106.2 | % | ||||||
Customer counts: | ||||||||||||||||||
Retail electricity customers (end of period and in thousands) (d): | ||||||||||||||||||
Residential | 1,862 | 1,914 | 1,914 | 1,857 | 1,909 | 1,839 | ||||||||||||
Small business (a) | 262 | 275 | 275 | 274 | 276 | 275 | ||||||||||||
Large business and other customers | 23 | 25 | 25 | 33 | 27 | 35 | ||||||||||||
Total retail electricity customers | 2,147 | 2,214 | 2,214 | 2,164 | 2,212 | 2,149 | ||||||||||||
| (a) | Customers with demand of less than 1 MW annually. |
| (b) | Calculated using average number of customers for the period. |
| (c) | Weather data is obtained from Weatherbank, Inc., an independent company that collects and archives weather data from reporting stations of the National Oceanic and Atmospheric Administration (a federal agency under the US Department of Commerce). Normal is defined as the average over a 20-year period. |
| (d) | Based on number of meters. Typically, large business and other customers have more than one meter; therefore, number of meters does not reflect the number of individual customers. Each of the year ended December 31, 2008 and three months ended December 31, 2008 and 2007 amounts reflects reclassification of 18 thousand meters, and the nine months ended September 30, 2007 amounts reflect the reclassification of 19 thousand meters from residential to small business to conform to current presentation. |
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Competitive Electric Segment
Revenue and Commodity Hedging and Trading Activities
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Three Months Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Nine Months Ended September 30, 2008 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||||||||
Operating revenues: | ||||||||||||||||||||||||||
Retail electricity revenues: | ||||||||||||||||||||||||||
Residential | $ | 3,806 | $ | 3,782 | $ | 816 | $ | 654 | $ | 2,966 | $ | 3,064 | ||||||||||||||
Small business (a) | 1,164 | 1,099 | 247 | 202 | 852 | 880 | ||||||||||||||||||||
Large business and other customers | 1,261 | 1,447 | 304 | 286 | 1,143 | 1,070 | ||||||||||||||||||||
Total retail electricity revenues | 6,231 | 6,328 | 1,367 | 1,142 | 4,961 | 5,014 | ||||||||||||||||||||
Wholesale electricity revenues (b) | 1,463 | 3,329 | 532 | 505 | 2,797 | 1,637 | ||||||||||||||||||||
Net sales (purchases) of balancing electricity to/from ERCOT | (80 | ) | (214 | ) | 13 | (9 | ) | (227 | ) | (14 | ) | |||||||||||||||
Amortization of intangibles (c) | 5 | (36 | ) | (21 | ) | (50 | ) | (15 | ) | — | ||||||||||||||||
Other operating revenues | 292 | 380 | 88 | 83 | 293 | 247 | ||||||||||||||||||||
Total operating revenues | $ | 7,911 | $ | 9,787 | $ | 1,979 | $ | 1,671 | $ | 7,809 | $ | 6,884 | ||||||||||||||
Net gain (loss) from commodity hedging and trading activities: | ||||||||||||||||||||||||||
Unrealized net gains (losses) from changes in fair value | $ | 1,741 | $ | 2,290 | $ | 2,527 | $ | (1,469 | ) | $ | (237 | ) | $ | (646 | ) | |||||||||||
Unrealized net gains (losses) representing reversals of previously recognized fair values of positions settled in the current period | (464 | ) | (9 | ) | 59 | (87 | ) | (68 | ) | (76 | ) | |||||||||||||||
Realized net gains (losses) on settled positions | 459 | (97 | ) | (154 | ) | 64 | 57 | 168 | ||||||||||||||||||
Total gain (loss) | $ | 1,736 | $ | 2,184 | $ | 2,432 | $ | (1,492 | ) | $ | (248 | ) | $ | (554 | ) | |||||||||||
| (a) | Customers with demand of less than 1 MW annually. |
| (b) | Upon settlement of physical derivative power sales and purchase contracts that are marked-to-market in net income, wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, as required by accounting rules, instead of the contract price. As a result, these line item amounts include a noncash component, which the company considers “unrealized.” These amounts are as follows: |
| Successor | Predecessor | ||||||||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Three Months Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Nine Months Ended September 30, 2008 | Period from January 1, 2007 through October 10, 2007 | ||||||||||||||||||
Reported in revenues | $ | (166 | ) | $ | 42 | $ | (113 | ) | $ | — | $155 | $ | — | ||||||||||
Reported in fuel and purchased power costs | 114 | 6 | 77 | — | (71 | ) | — | ||||||||||||||||
Net gain (loss) | $ | (52 | ) | $ | 48 | $ | (36 | ) | $ | — | $ | 84 | $ | — | |||||||||
| (c) | Represents amortization of the intangible net asset value of retail and wholesale power sales agreements resulting from purchase accounting. |
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Competitive Electric Segment
Production, Purchased Power and Delivery Cost Data
| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Three Months Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Nine Months Ended September 30, 2008 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Fuel, purchased power costs and delivery fees ($ millions): | ||||||||||||||||||||
Nuclear fuel | $ | 114 | $ | 95 | $ | 26 | $ | 21 | $ | 69 | $ | 66 | ||||||||
Lignite/coal | 670 | 640 | 155 | 127 | 485 | 467 | ||||||||||||||
Total baseload fuel | 784 | 735 | 181 | 148 | 554 | 533 | ||||||||||||||
Natural gas fuel and purchased power (a) | 1,224 | 2,881 | 349 | 302 | 2,532 | 1,435 | ||||||||||||||
Amortization of intangibles (b) | 292 | 318 | 72 | 67 | 246 | — | ||||||||||||||
Other costs | 202 | 351 | 47 | 68 | 304 | 213 | ||||||||||||||
Fuel and purchased power costs | 2,502 | 4,285 | 649 | 585 | 3,636 | 2,181 | ||||||||||||||
Delivery fees (c) | 1,432 | 1,315 | 305 | 267 | 1,010 | 1,028 | ||||||||||||||
Total | $ | 3,934 | $ | 5,600 | $ | 954 | $ | 852 | $ | 4,646 | $ | 3,209 | ||||||||
| Successor | Successor | Predecessor | ||||||||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Three Months Ended December 31, 2008 | Three Months Ended December 31, 2007 | Nine Months Ended September 30, 2008 | Nine Months Ended September 30, 2007 | |||||||||||||||||||
Fuel and purchased power costs (which excludes generation plant operating costs) per MWh: | ||||||||||||||||||||||||
Nuclear fuel | $ | 5.66 | $ | 4.92 | $ | 5.46 | $ | 4.64 | $ | 4.75 | $ | 4.59 | ||||||||||||
Lignite/coal (d) | $ | 16.47 | $ | 15.80 | $ | 15.68 | $ | 13.48 | $ | 15.83 | $ | 14.31 | ||||||||||||
Natural gas fuel and purchased power | $ | 43.10 | $ | 81.99 | $ | 46.63 | $ | 60.04 | $ | 91.55 | $ | 62.29 | ||||||||||||
Delivery fees per MWh | $ | 28.09 | $ | 26.33 | $ | 28.66 | $ | 26.64 | $ | 25.69 | $ | 25.60 | ||||||||||||
Production and purchased power volumes (GWh): | ||||||||||||||||||||||||
Nuclear | 20,104 | 19,218 | 4,770 | 5,157 | 14,448 | 13,664 | ||||||||||||||||||
Lignite/coal | 45,684 | 44,923 | 11,226 | 12,197 | 33,697 | 34,297 | ||||||||||||||||||
Total baseload generation | 65,788 | 64,141 | 15,996 | 17,354 | 48,145 | 47,961 | ||||||||||||||||||
Natural gas-fueled generation | 2,447 | 4,122 | 279 | 500 | 3,843 | 3,491 | ||||||||||||||||||
Purchased power | 26,018 | 31,018 | 7,202 | 5,483 | 23,816 | 18,619 | ||||||||||||||||||
Total energy supply | 94,253 | 99,281 | 23,477 | 23,337 | 75,804 | 70,071 | ||||||||||||||||||
Less line loss and power imbalances (e) | 1,352 | 3,095 | 391 | 912 | 2,704 | 3,472 | ||||||||||||||||||
Net energy supply volumes | 92,901 | 96,186 | 23,086 | 22,425 | 73,100 | 66,599 | ||||||||||||||||||
Baseload capacity factors: | ||||||||||||||||||||||||
Nuclear | 100.0 | % | 95.2 | % | 94.0 | % | 101.6 | % | 95.6 | % | 90.8 | % | ||||||||||||
Lignite/coal | 86.5 | % | 87.6 | % | 86.3 | % | 94.5 | % | 87.7 | % | 89.7 | % | ||||||||||||
Total baseload | 90.3 | % | 89.8 | % | 88.5 | % | 96.5 | % | 89.9 | % | 90.0 | % | ||||||||||||
| (a) | See note (b) on previous page. |
| (b) | Represents amortization of the intangible net asset values of emission credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel resulting from purchase accounting. |
| (c) | Includes delivery fee charges from Oncor that are eliminated in consolidation. |
| (d) | Includes depreciation and amortization of lignite mining assets, which is reported in the depreciation and amortization expense line item, but is part of overall fuel costs. |
| (e) | Includes physical purchases and sales, the financial results of which are reported in commodity hedging and trading activities in the income statement. |
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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 $1.866 billion, or 56%, to $1.463 billion in 2009 as compared to 2008 when wholesale revenues increased 55%. Volatility in wholesale revenues and purchased power costs reflects movements in natural gas prices, as lower natural gas prices in 2009 drove a 46% decline in average wholesale electricity sales prices. Reported wholesale revenues and purchased power costs also reflect changes in volumes of bilateral contracting activity entered into to mitigate the effects of demand volatility and congestion. Results in 2009 reflect lower demand volatility and a decline in congestion, which drove an 8% decline in wholesale sales volumes.
Bilateral electricity contracting activity includes hedging transactions that utilize contracts for physical delivery. Wholesale sales and purchases of electricity are reported gross in the income statement if the transactions are scheduled for physical delivery with ERCOT.
Comparisons of wholesale balancing activity, reported net, are generally not meaningful because the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, which are highly variable. The activity in 2009 reflected reduced volatility and congestion, in part due to actions taken by ERCOT.
Retail electricity revenues declined $97 million, or 2%, to $6.231 billion and reflected the following:
| • | Lower average pricing contributed $242 million to the revenue decline. The change in average pricing reflected lower average contracted business rates driven by lower wholesale electricity prices, partially offset by higher average pricing in the residential and non-contract business markets resulting from advanced meter surcharges as well as customer mix. |
| • | Retail sales volume growth of 2% increased revenues by $145 million. Volumes rose in the business markets driven by changes in customer mix resulting from contracting activity, but declined slightly in the residential market driven by a 3% decrease in customers. |
Other operating revenues decreased $88 million, or 23%, to $292 million in 2009 due to lower natural gas prices and lower volumes on sales of natural gas to industrial customers.
The change in operating revenues also reflected a $41 million decrease in amortization of intangible assets arising from purchase accounting reflecting expiration of retail sales contracts.
Fuel, purchased power costs and delivery fees decreased $1.666 billion, or 30%, to $3.934 billion in 2009. This decrease was driven by lower purchased power costs due to the effect of lower natural gas prices, decreased demand volatility and reduced congestion as discussed above regarding wholesale revenues. Lower costs of replacement power during unplanned generation unit repair outages contributed to improved margin. Other factors contributing to lower fuel and purchased power costs included lower natural gas-fueled generation and lower related fuel costs ($374 million), the effect of lower natural gas prices on natural gas purchased for sale to industrial customers ($116 million) and lower amortization of intangible assets arising from purchase accounting ($26 million).
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Overall baseload generation production increased 3% in 2009 reflecting a 5% increase in nuclear production and a 2% increase in lignite/coal-fueled production. The increase in nuclear production, which reflects two refueling outages in 2008 compared to one refueling outage in 2009 and investments to increase generation capacity, resulted in improved margin. The increase in lignite/coal-fueled production reflected generation from the new units placed in service in the fourth quarter 2009, partially offset by generation reductions during certain periods when power could be purchased in the wholesale market at prices below production costs, which was largely due to lower natural gas prices and higher wind generation availability.
Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the years ended December 31, 2009 and 2008, which totaled $1.736 billion and $2.184 billion in net gains, respectively:
Year Ended December 31, 2009 —Unrealized mark-to-market net gains totaling $1.277 billion included:
| • | $1.260 billion in net gains related to hedge positions, which includes $1.719 billion in net gains from changes in fair value, driven by the impact of lower forward natural gas prices on the value of positions in the long-term hedging program, and $459 million in net losses that represent reversals of previously recorded net gains on positions settled in the period, and |
| • | $17 million in net gains related to trading positions, which includes $22 million in net gains from changes in fair value and $5 million in net losses that represent reversals of previously recorded net gains on positions settled in the period. |
Realized net gains totaling $459 million included:
| • | $449 million in net gains related to positions that primarily hedged electricity revenues recognized in the period, and |
| • | $10 million in net gains related to trading positions. |
Year Ended December 31, 2008— Unrealized mark-to-market net gains totaling $2.281 billion included:
| • | $2.324 billion in net gains related to hedge positions, which includes $2.282 billion in net gains from changes in fair value and $42 million in net gains that represent reversals of previously recorded fair values of positions settled in the period; |
| • | $68 million in “day one” net losses related to large hedge positions (see Note 18 to 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 3 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 Notes 2 and 20 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 10 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 3 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 10 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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Competitive Electric Segment — Financial Results — Three Months Ended December 31, 2008 Compared to Successor Period from October 11, 2007 through December 31, 2007
Operating revenues increased $308 million, or 18%, to $1.979 billion in 2008.
Retail electricity revenues increased $225 million, or 20%, to $1.367 billion in 2008 and reflected the following:
| • | The increase in retail electricity revenues was largely due to $186 million in revenues attributable to the ten fewer days in the 2007 period. |
| • | Higher average pricing in all markets contributed to the revenue increase, with residential rates increasing an average of 7%, and higher average rates in the business markets reflecting a change in customer mix in the large business market. |
| • | The effect of higher retail pricing was partially offset by the effect of a 6% decline in total retail sales volumes driven by the business markets. The lower sales volumes in the business markets reflected a decline in commercial and industrial activity due to economic conditions. |
| • | Total retail electricity customer counts at December 31, 2008 increased 2% from December 31, 2007, driven by a 3% increase in residential customers. |
Wholesale electricity revenues increased $27 million, or 5%, to $532 million in 2008. The increase in wholesale electricity revenues reflected $66 million in revenues attributable to the ten fewer days in the 2007 period. The change also reflected lower wholesale electricity prices driven by lower natural gas prices.
The change in operating revenues also reflected a $29 million decrease in amortization of intangible assets arising in purchase accounting.
Fuel, purchased power costs and delivery fees increased $102 million, or 12%, to $954 million in 2008. The increase was largely due to $123 million in costs attributable to the ten fewer days in the 2007 period.
Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the three months ended December 31, 2008 and the Successor period from October 11, 2007 through December 31, 2007:
Three Months Ended December 31, 2008— Net gain totaling $2.432 billion included:
| • | Unrealized mark-to-market net gains of $2.586 billion, substantially all of which related to commodity hedge positions and |
| • | Realized net losses totaling $154 million, including $101 million in net losses related to commodity hedge positions that primarily offset hedged electricity revenues recognized in the period and $53 million in net losses related to trading positions. |
Period from October 11 through December 31, 2007— Net losses totaling $1.492 billion included:
| • | Unrealized mark-to-market net losses of $1.556 billion, substantially all of which related to commodity hedge positions and |
| • | Realized net gains totaling $64 million consisting primarily of net gains related to commodity hedge positions that offset hedged electricity revenues and fuel and purchased power costs recognized in the period. |
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Operating costs increased $53 million, or 43%, to $177 million in 2008. The increase was partially due to $19 million in costs attributable to the ten fewer days in the 2007 period. The increase in operating costs also reflects higher maintenance costs related to the timing and scope of planned and unplanned outages in baseload generation facilities, higher staffing and benefits costs and expenses associated with operational readiness of the generation units under construction.
Depreciation and amortization decreased $50 million, or 16%, to $265 million in 2008. The decrease in depreciation and amortization reflected lower amortization expense related to the intangible value of customer relationships, partially offset by incremental depreciation expense from stepped-up property, plant and equipment values, both related to purchase accounting and $8 million in expense attributable to the ten fewer days in the 2007 period.
SG&A expenses increased $29 million, or 19%, to $183 million in 2008. The increase was partially due to $15 million in expenses attributable to the ten fewer days in the 2007 period. The increase in SG&A expenses also reflected higher bad debt expense due in part to the effects of Hurricane Ike and higher salaries and contractor costs to support customer growth initiatives and computer system enhancements, net of a decrease in fees associated with the sale of accounts receivable program and lower advertising-related costs.
See Note 3 to Financial Statements for discussion of the $8.0 billion goodwill impairment charge recorded in the fourth quarter of 2008.
Other income totaled $26 million in 2008 and $2 million in 2007. Other income in 2008 included a $21 million insurance recovery for damages to certain mining equipment. Other deductions totaled $715 million in 2008 and $8 million in 2007. Other deductions in 2008 included a charge of $481 million for the impairment of a trade name intangible asset (see Note 3 to Financial Statements) and a $229 million charge to write down the natural gas-fueled generation facilities to fair value (see Note 5 to Financial Statements).
Interest income increased $5 million to $15 million in 2008 reflecting higher average balances of notes/advances to parent.
Interest expense and related charges increased $1.578 billion to $2.187 billion in 2008. The increase was driven by an unrealized mark-to-market net loss on interest rate swaps of $1.512 billion.
Income tax expense on a pre-tax loss for 2008 totaled $2 million compared to a $656 million income tax benefit on a pre-tax loss in 2007. Excluding the impact of the $8.0 billion goodwill impairment in 2008, the effective rate on a pre-tax loss was 3.1% in 2008 compared to 34.5% in 2007. (This nondeductible charge distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion.) The decrease in the rate is driven by the unfavorable impact of tax provision adjustments recorded in 2008 on a small pre-tax loss.
After-tax results for the segment declined by $6.822 billion to a loss of $8.067 billion driven by impairment charges related to goodwill, the trade name intangible asset and the natural gas-fueled generation facilities and the unrealized mark-to-market net losses on interest rate swaps, partially offset by the change in unrealized mark-to-market values of commodity hedge positions in the long-term hedging program.
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Competitive Electric Segment — Financial Results — Nine Months Ended September 30, 2008 Compared to Predecessor Period from January 1, 2007 through October 10, 2007
Operating revenues increased $925 million, or 13%, to $7.809 billion in 2008.
Wholesale electricity revenues increased $1.160 billion, or 71%. A 40% increase in average wholesale electricity prices driven by higher natural gas prices contributed $797 million to revenue growth and a 27% increase in sales volumes contributed $429 million. The rise in natural gas prices reflected the overall trend of higher energy prices and increased demand in natural gas-fueled generation due to warmer weather in 2008. Higher wholesale sales and purchase volumes reflected several factors, including increased demand (due to warmer weather), baseload plant outages and congestion, as well as increased near-term bilateral power contracting activity due in part to increased demand and market volatility in 2008. The higher natural gas prices also contributed to the increase in fuel and purchased power costs. The increase in wholesale electricity revenues and sales volumes was partially offset by $66 million in revenues attributable to the ten additional days in the 2007 period.
The $53 million, or 1%, decrease in retail electricity revenues reflected the following:
| • | The ten additional days in the 2007 period contributed $186 million to the decrease in retail electricity revenues. |
| • | The decrease in retail electricity revenues was partially offset by a 2% increase in retail sales volumes that increased revenues by $107 million. Residential volumes increased 4% reflecting the effects of warmer than normal weather in 2008 combined with the cooler than normal weather experienced in 2007 and a 4% increase in residential customer counts. Business and other customer volumes were comparable with 2007. |
| • | The decrease in retail electricity revenues was also partially offset by higher average pricing that increased revenues by $26 million. Higher average retail pricing reflected higher prices in the business markets driven by higher natural gas prices, partially offset by an approximate $108 million effect of lower pricing in the residential customer market. Lower residential pricing reflected the effect of a 6% price discount in March 2007, an additional 4% price discount in June 2007 and another 5% price discount in October 2007 to those residential customers in Oncor’s service territory with month-to-month service plans and a rate equivalent to the former price-to-beat. |
Comparisons of wholesale balancing activity, reported net, are generally not meaningful because the activity represents intraday purchases and sales transactions with ERCOT for real-time balancing purposes, as measured in 15-minute intervals, which are highly variable. The relatively large amount in 2008 reflects weather-driven volatility, generation facility outages and congestion effects.
Other operating revenues increased $46 million, or 19%, to $293 million primarily due to higher retail natural gas revenues reflecting increased prices, the effect of which was partially offset by $11 million in revenues attributable to the ten additional days in the 2007 period.
Fuel, purchased power costs and delivery fees increased $1.437 billion, or 45%, to $4.646 billion. The increase was driven by higher purchased power costs, reflecting 28% growth in purchased power volumes as well as the effect of higher natural gas prices on wholesale power prices. The increase also reflected greater utilization of natural gas-fueled generation facilities to meet peak demand and a 56% increase in fuel costs per MWh in those facilities due to higher natural gas prices. Higher fuel costs also reflected higher usage and prices (including transportation costs) of purchased coal. The increase reflects $246 million of net expense recorded in the 2008 period representing amortization of the intangible net asset values of environmental credits, coal purchase contracts and power purchase agreements and the stepped-up value of nuclear fuel resulting from purchase accounting. Other cost increases included $101 million related primarily to congestion-related charges and $41 million in higher costs of natural gas for resale. The increase in fuel, purchased power costs and delivery fees was partially offset by $123 million in costs attributable to the ten additional days in the 2007 period.
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Following is an analysis of amounts reported as net gain (loss) from commodity hedging and trading activities for the nine months ended September 30, 2008 and the Predecessor period from January 1, 2007 through October 10, 2007, which totaled $248 million and $554 million in net losses, respectively:
Nine Months Ended September 30, 2008— Unrealized mark-to-market net losses totaling $305 million include:
| • | $250 million in net losses related to hedge positions, which includes $248 million in net losses from changes in fair value and $2 million in net losses that represent reversals of previously recorded fair values of positions settled in the period; |
| • | $69 million in “day one” net losses related to large hedge positions (see Note 18 to Financial Statements), and |
| • | $13 million in net gains related to trading positions, which includes $79 million in net gains from changes in fair value and $66 million in net losses that represent reversals of previously recorded fair values of positions settled in the period. |
Realized net gains totaling $57 million include:
| • | $76 million in net losses related to hedge positions that primarily offset hedged electricity revenues recognized in the period, and |
| • | $133 million in net gains related to trading positions. |
Period from January 1, 2007 through October 10, 2007 —Unrealized mark-to-market net losses totaling $722 million include:
| • | $566 million in net losses related to hedge positions, which includes $528 million in net losses from changes in fair value and $38 million in net losses that represent reversals of previously recorded fair values of positions settled in the period; |
| • | $90 million in hedge ineffectiveness net gains, which includes $111 million of net gains from changes in fair values and $21 million in net losses that represent reversals of previously recorded ineffectiveness net gains related to positions settled in the period. These amounts relate to positions accounted for as cash flow hedges; |
| • | $45 million in net losses related to trading positions, which includes $28 million in net losses from changes in fair values and $17 million in net losses that represent reversals of previously recorded fair values of positions settled in the period; |
| • | $231 million in “day one” losses related to large hedge positions entered into at below-market prices, and |
| • | a $30 million “day one” gain related to a power purchase agreement. |
Realized net gains totaling $168 million include:
| • | $125 million in net gains related to hedge positions that offset hedged electricity revenues and fuel and purchased power costs recognized in the period, and |
| • | $43 million in net gains related to trading positions. |
Operating costs increased $29 million, or 6%, to $500 million in 2008. The increase reflects $36 million in higher maintenance costs related to the timing and scope of planned and unplanned outages in baseload generation facilities, $11 million in costs related to combustion turbines now being operated for our own benefit, $10 million in higher property taxes and $5 million of expenses associated with operational readiness of the generation units under construction, partially offset by $7 million in costs in 2007 for utilization of SO2credits for the lignite/coal-fueled generation plants and $3 million in individually insignificant items. The increase in operating costs was partially offset by $19 million in costs attributable to the ten additional days in the 2007 period.
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Depreciation and amortization increased $574 million to $827 million. The increase includes $502 million of incremental depreciation expense from stepped-up property, plant and equipment values and $38 million in incremental amortization expense related to the intangible value of customer relationships, both resulting from the effects of purchase accounting. The remaining increase primarily reflects normal additions and replacements of equipment in generation operations. The increase in depreciation and amortization was partially offset by $8 million in costs attributable to the ten additional days in the 2007 period.
SG&A expenses increased $10 million, or 2%, to $499 million in 2008. The increase reflects:
| • | $26 million in higher expenses in the retail operations, primarily increased employees and labor costs to support customer growth initiatives and increased marketing and computer systems enhancement costs, net of a $6 million decrease in fees associated with the sale of accounts receivable program, and |
| • | $16 million in higher retail customer bad debt expense, |
partially offset by
| • | $15 million in expenses attributable to the ten additional days in the 2007 period, and |
| • | lower administrative costs related to generation facility development activities reflecting the 2007 cancellation of certain coal-fueled generation projects. |
Other income totaled $8 million in 2008 and $22 million in 2007. The 2007 amount includes $7 million of royalty income and $6 million in penalties received due to nonperformance under a coal transportation agreement. Other income totaling $3 million in 2007 was attributable to the ten additional days in the period.
Other deductions totaled $559 million in 2008 and $735 million in 2007. The 2008 amount includes $501 million in impairment charges related to NOx and SO2 environmental allowances intangible assets discussed in Note 3 to Financial Statements and $26 million in charges to reserve for net receivables (excluding termination related costs) from terminated hedging transactions with subsidiaries of Lehman Brothers Holdings Inc., which has filed for protection under Chapter 11 of the US Bankruptcy Code. The 2007 amount includes net charges of $812 million in connection with the cancellation of the development of eight coal-fueled generation units, a $48 million reduction in the liability previously recorded for leases related to gas-fueled combustion turbines that we had ceased operating for our own benefit and a $10 million charge related to the termination of a railcar operating lease. See Note 10 to Financial Statements for more details.
Interest income decreased $225 million, or 83%, to $46 million in 2008 reflecting lower average balances of notes/advances to parent. The ten additional days in the 2007 period contributed $11 million to the decrease.
Interest expense and related charges increased $1.467 billion to $1.824 billion in 2008. The increase reflects $1.672 billion due to higher average borrowings, driven by the Merger-related financings, partially offset by $150 million in increased capitalized interest, a $36 million unrealized mark-to-market gain related to interest rate swaps and $11 million of amortization of debt fair value discount resulting from purchase accounting. The increase was also net of $15 million in additional interest in the 2007 period attributable to the ten additional days in the period.
Income tax benefit on a pretax loss totaled $452 million in 2008 and income tax expense on pretax income totaled $306 million in 2007. The 2007 amount includes a deferred tax benefit of $32 million related to an amendment of the Texas margin tax by the Texas legislature. Excluding the effect of this 2007 item, the effective income tax rates were 34.4% on a loss in 2008 compared to 32.9% on income in 2007. (The deferred tax benefit in 2007 distorts the comparison; therefore it has been excluded for purposes of a more meaningful discussion.) The increase in the effective tax rate is due to a lower lignite depletion benefit in 2008, partially offset by the effect of the Texas margin tax under which interest expense is not deductible.
Net income (loss) decreased $1.584 billion to a net loss of $862 million in 2008 driven by higher net interest expense, the impairment of environmental allowances intangible assets and the effects of purchase accounting, partially offset by the effect of the 2007 impairment charge in connection with the cancellation of certain generation facility development activities and the decrease in net unrealized mark-to-market losses on positions in the long-term hedging program.
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Regulated Delivery Segment
The following tables present financial operating results of the Regulated Delivery segment for the Successor periods of the years ended December 31, 2009 and 2008, the three months ended December 31, 2008, the period from October 11, 2007 through December 31, 2007 and the nine months ended September 30, 2008, and for the Predecessor period from January 1, 2007 through October 10, 2007. Volumetric and other statistical data have been presented as of and for the Successor periods of the years ended December 31, 2009 and 2008, the three months ended December 31, 2008 and 2007 and the nine months ended December 31, 2008, and for the Predecessor period for the nine months ended September 30, 2007.
Financial Results
| Successor | Predecessor | |||||||||||||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Three Months Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Nine Months Ended September 30, 2008 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||||||||||
Operating revenues | $ | 2,690 | $ | 2,580 | $ | 612 | $ | 532 | $ | 1,969 | $ | 1,987 | ||||||||||||||||
Operating costs | (908 | ) | (828 | ) | (208 | ) | (182 | ) | (620 | ) | (637 | ) | ||||||||||||||||
Depreciation and amortization | (557 | ) | (492 | ) | (122 | ) | (96 | ) | (370 | ) | (366 | ) | ||||||||||||||||
Selling, general and administrative expenses | (194 | ) | (164 | ) | (38 | ) | (45 | ) | (126 | ) | (139 | ) | ||||||||||||||||
Franchise and revenue-based taxes | (250 | ) | (255 | ) | (69 | ) | (62 | ) | (186 | ) | (198 | ) | ||||||||||||||||
Impairment of goodwill | — | (860 | ) | (860 | ) | — | — | — | ||||||||||||||||||||
Other income | 49 | 45 | 11 | 11 | 34 | 3 | ||||||||||||||||||||||
Other deductions | (34 | ) | (19 | ) | (2 | ) | (7 | ) | (17 | ) | (27 | ) | ||||||||||||||||
Interest income | 43 | 45 | 11 | 12 | 34 | 44 | ||||||||||||||||||||||
Interest expense and related charges | (346 | ) | (317 | ) | (89 | ) | (70 | ) | (229 | ) | (242 | ) | ||||||||||||||||
Income (loss) before income taxes | 493 | (265 | ) | (754 | ) | 93 | 489 | 425 | ||||||||||||||||||||
Income tax expense (a) | (173 | ) | (221 | ) | (41 | ) | (30 | ) | (180 | ) | (160 | ) | ||||||||||||||||
Net income (loss) | $ | 320 | $ | (486 | ) | $ | (795 | ) | $ | 63 | $ | 309 | $ | 265 | ||||||||||||||
| (a) | Effective with the sale of noncontrolling interests (see Note 15 to 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. |
Operating Data
| Successor | Successor | Predecessor | ||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Three Months Ended December 31, 2008 | Three Months Ended December 31, 2007 | Nine Months Ended September 30, 2008 | Nine Months Ended September 30, 2007 | |||||||
Operating statistics – volumes: | ||||||||||||
Electric energy billed volumes (GWh) | 103,376 | 107,828 | 23,969 | 25,784 | 83,859 | 79,645 | ||||||
Reliability statistics (a): | ||||||||||||
System Average Interruption Duration Index (SAIDI) (nonstorm) | 84.5 | 85.4 | 85.4 | 77.9 | 82.6 | 79.2 | ||||||
System Average Interruption Frequency Index (SAIFI) (nonstorm) | 1.1 | 1.1 | 1.1 | 1.1 | 1.1 | 1.1 | ||||||
Customer Average Interruption Duration Index (CAIDI) (nonstorm) | 77.2 | 74.7 | 74.7 | 70.6 | 75.3 | 69.5 | ||||||
Electric points of delivery (end of period and in thousands): | ||||||||||||
Electricity distribution points of delivery (based on number of meters) | 3,145 | 3,123 | 3,123 | 3,093 | 3,116 | 3,087 | ||||||
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| Successor | Predecessor | |||||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Three Months Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Nine Months Ended September 30, 2008 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Operating revenues: | ||||||||||||||||||||
Electricity distribution revenues (b): | ||||||||||||||||||||
Affiliated (TCEH) | $ | 1,017 | $ | 998 | $ | 226 | $ | 208 | $ | 773 | $ | 821 | ||||||||
Nonaffiliated | 1,339 | 1,264 | 304 | 257 | 960 | 921 | ||||||||||||||
Total distribution revenues | 2,356 | 2,262 | 530 | 465 | 1,733 | 1,742 | ||||||||||||||
Third-party transmission revenues | 299 | 280 | 73 | 60 | 207 | 199 | ||||||||||||||
Other miscellaneous revenues | 35 | 38 | 9 | 7 | 29 | 46 | ||||||||||||||
Total operating revenues | $ | 2,690 | $ | 2,580 | $ | 612 | $ | 532 | $ | 1,969 | $ | 1,987 | ||||||||
| (a) | SAIDI is the average number of minutes electric service is interrupted per consumer in a year. SAIFI is the average number of electric service interruptions per consumer in a year. CAIDI is the average duration in minutes per electric service interruption in a year. The statistics presented are based on the preceding twelve months’ data. |
| (b) | Includes transition charge revenue associated with the issuance of securitization bonds totaling $147 million and $140 million for the years ended December 31, 2009 and 2008, respectively; $32 million for the three months ended December 31, 2008; $29 million for the period October 11, 2007 through December 31, 2007; $108 million for the nine months ended September 30, 2008 and $116 million for the period January 1, 2007 through October 10, 2007. Also includes disconnect/reconnect fees and other discretionary revenues for services requested by REPs. |
Regulated Delivery Segment — Financial Results — Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Operating revenues increased $110 million, or 4%, to $2.690 billion in 2009. The increase reflected:
| • | $55 million from increased distribution tariffs, including the August 2009 rate review order; |
| • | $28 million from a surcharge to recover advanced metering deployment costs and $11 million from a surcharge to recover additional energy efficiency costs, both of which became effective with the January 2009 billing cycle; |
| • | $20 million in higher transmission revenues reflecting rate increases to recover ongoing investment in the transmission system; |
| • | an estimated $14 million impact from growth in points of delivery; |
| • | $9 million performance bonus for meeting PUCT energy efficiency targets, and |
| • | $7 million in higher charges to REPs related to transition bonds (with an offsetting increase in amortization of the related regulatory asset), |
partially offset by an estimated $27 million in lower average consumption primarily due to the effects of milder weather and general economic conditions and $7 million due to less requested REP discretionary and third-party maintenance services.
Operating costs increased $80 million, or 10%, to $908 million in 2009. The increase reflected $45 million in higher fees paid to other transmission entities, $21 million in additional expense recognition as a result of the PUCT’s August 2009 final order in the rate review (see discussion immediately below) and $10 million in costs related to programs designed to improve customer electricity demand efficiency, the majority of which are reflected in the revenue increases discussed above.
Under accounting rules for rate regulated utilities, certain costs are deferred as regulatory assets (see Note 25 to 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 (see “Regulation and Rates” below), Oncor began to amortize as operating costs or SG&A expenses certain costs previously deferred as regulatory assets over the recoverability period under the rate review order and recognized higher costs related to the current period. The additional expense recognized included $14 million related to storm recovery costs and $10 million related to pension and OPEB costs (including $3 million reported in SG&A expense).
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Depreciation and amortization increased $65 million, or 13%, to $557 million in 2009. The increase reflected $34 million in higher depreciation due to ongoing investments in property, plant and equipment (including $11 million related to advanced meters), $24 million due to increased depreciation and amortization rates implemented upon the PUCT approval of new tariffs in September 2009 and $7 million in higher amortization of regulatory assets associated with securitization bonds (with an offsetting increase in revenues).
SG&A expenses increased $30 million, or 18%, to $194 million in 2009. The increase reflected $12 million related to advanced meters and $3 million in additional expense recognition as a result of the PUCT’s final order in the rate review, both of which have related revenue increases, $8 million in higher professional and contractor fees driven by outsourcing transition and CREZ development activities and $6 million in higher costs related to employee benefit plans, partially offset by a $3 million one-time reversal of bad debt expense due to the PUCT’s finalization of the Certification of Retail Electric Providers rule in April 2009. Write-offs of uncollectible amounts owed by nonaffiliated REPs are deferred as a regulatory asset (see “Regulation and Rates”).
Taxes other than amounts related to income taxes decreased $5 million, or 2%, to $250 million in 2009 reflecting a decrease in local franchise fees due to decreased volumes of electricity delivered.
See Note 3 to 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 2 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 25 to Financial Statements). The 2009 and 2008 amounts included costs totaling $2 million and $13 million, respectively, associated with the 2006 rate settlement with certain cities.
Interest income decreased $2 million, or 4%, to $43 million in 2009. The decrease reflected $4 million in lower reimbursement of transition bond interest from TCEH due to lower remaining principal amounts of the bonds and $2 million in lower interest income on temporary cash investments and restricted cash due to lower interest rates, partially offset by $4 million in higher earnings on investments held for certain employee benefit plans.
Interest expense and related charges increased $29 million, or 9%, to $346 million in 2009. The increase reflected $17 million in higher average borrowings, reflecting ongoing capital investments. The increase also reflected $12 million due to higher average interest rates, which was driven by refinancing of short-term borrowings with $1.5 billion of senior secured notes issued in September 2008. The majority of the proceeds of the September 2008 notes issuance was used to pay outstanding short-term borrowings under Oncor’s credit facility.
Income tax expense totaled $173 million in 2009 compared to $221 million in 2008. The effective rate decreased to 35.1% in 2009 from 37.2% in 2008, excluding the impact of the $860 million goodwill impairment in 2008. (This nondeductible charge distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion.) The decrease in the rate was driven by the reversal of accrued interest due to the favorable resolution of uncertain tax positions.
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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Regulated Delivery Segment — Financial Results — Three Months Ended December 31, 2008 Compared to Successor Period from October 11, 2007 through December 31, 2007
Operating revenues increased $80 million, or 15%, to $612 million in 2008. The increase is largely due to $68 million in revenues attributable to the ten fewer days in the 2007 period. The increase also reflected increased distribution tariffs to recover transmission costs, the impact of growth in points of delivery and higher transmission revenues primarily due to a rate increase to recover ongoing investment in the transmission system, partially offset by lower average consumption due to the effects of milder weather.
Operating costs increased $26 million, or 14%, to $208 million in 2008. The increase is largely due to $21 million in costs attributable to the ten fewer days in the 2007 period. The increase also reflected higher property taxes and higher fees paid to other transmission entities, partially offset by lower vegetation management expenses.
Depreciation and amortization increased $26 million, or 27%, to $122 million in 2008. The increase included $12 million in costs attributable to the ten fewer days in the 2007 period. The remaining increase largely reflected higher depreciation due to ongoing investments in property, plant and equipment.
SG&A expenses decreased $7 million, or 16%, to $38 million in 2008. The decrease reflected lower incentive compensation expense and decreased employee benefit costs, partially offset by $2 million in costs attributable to the ten fewer days in the 2007 period.
Franchise and revenue-based taxes increased $7 million, or 11%, to $69 million in 2008. The increase is largely due to the ten fewer days in the 2007 period.
See Note 3 to Financial Statements for a discussion of the $860 million goodwill impairment charge recorded in 2008.
Other income totaled $11 million in both 2008 and 2007. The amounts reflected accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting. Other deductions totaled $2 million and $7 million in 2008 and 2007, respectively. The 2007 amount included costs associated with the 2006 rate settlement with certain cities totaling $6 million.
Interest income decreased $1 million, or 8%, to $11 million in 2008. The decrease reflected lower earnings on investments held for certain employee benefit plans, partially offset by $2 million in interest income attributable to the ten fewer days in the 2007 period.
Interest expense and related charges increased by $19 million, or 27%, to $89 million in 2008. The increase included $9 million in costs attributable to the ten fewer days in the 2007 period. The remaining increase reflected $7 million from higher average borrowings, reflecting ongoing capital investments, and $1 million from higher average interest rates.
Income tax expense totaled $41 million in 2008 compared to $30 million in 2007. The effective income tax rate increased to 38.7% in 2008, excluding the impact of the $860 million goodwill impairment charge, from 32.3% in 2007. (This nondeductible charge distorts the comparison; therefore, it has been excluded for purposes of a more meaningful discussion.) The increase in the effective rate was driven by the impact of higher Texas margin tax due in part to the effects of the tax sharing agreement in 2007 and higher accrued interest related to uncertain tax positions.
Net loss for 2008 totaled $795 million and net income for 2007 totaled $63 million. The change was driven by the $860 million goodwill impairment charge recorded in 2008.
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Regulated Delivery Segment — Financial Results — Nine Months Ended September 30, 2008 Compared to Predecessor Period from January 1, 2007 through October 10, 2007
Operating revenues decreased $18 million, or less than 1%, to $1.969 billion in 2008. The decreased revenue reflected:
| • | $68 million attributable to the ten additional days in the 2007 period; |
| • | $19 million in lower revenues due to the absence in 2008 of revenues for installation of third party equipment related to Oncor’s technology initiatives, and |
| • | $4 million in lower charges to REPs related to securitization bonds (with an offsetting decrease in amortization of the related regulatory asset), |
partially offset by:
| • | $32 million from increased distribution tariffs to recover higher transmission costs; |
| • | an estimated $16 million impact from growth in points of delivery; |
| • | $15 million in higher transmission revenues primarily due to rate increases to recover ongoing investment in the transmission system; |
| • | an estimated $3 million from higher average consumption, as the estimated effect of warmer weather was partially offset by usage declines, and |
| • | $7 million in increased miscellaneous revenues, including $3 million of revenues for services provided to REPs and other customers (with a related increase in operating costs) and $2 million of pole contact revenues. |
Operating costs decreased $17 million, or 3%, to $620 million in 2008. The decrease reflected:
| • | $21 million attributable to the ten additional days in the 2007 period, and |
| • | $18 million of lower expenses due to the absence in 2008 of costs for installation of third party equipment related to Oncor’s technology initiatives, |
partially offset by:
| • | $15 million in increased labor and benefits costs for restoration of service as a result of weather events, more stringent service requirements, increased services provided to REPs and other customers and equipment installation activities; |
| • | $3 million in higher vegetation management expenses, and |
| • | $3 million in software license and service expenses related to Oncor’s purchase of a broadband over power line (BPL) based “Smart Grid” network in May 2008. |
Depreciation and amortization increased $4 million, or 1%, to $370 million in 2008. The increase reflected $21 million in higher depreciation due to ongoing investments in property, plant and equipment, partially offset by $4 million in lower amortization of the regulatory assets associated with securitization bonds (with an offsetting decrease in revenues) and $12 million attributable to the ten additional days in the 2007 period.
SG&A expenses decreased $13 million, or 9%, to $126 million in 2008. The decrease reflected:
| • | $7 million in lower incentive compensation expense; |
| • | $5 million in lower fees due to Oncor’s exit from the sale of accounts receivable program; |
| • | $4 million in expenses in 2007 related to the rebranding of TXU Electric Delivery Company to Oncor Electric Delivery Company; |
| • | $2 million attributable to the ten additional days in the 2007 period, and |
| • | $1 million in decreased bad debt expense, |
partially offset by $4 million in higher professional fees and $4 million in increased employee benefits costs.
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Franchise and revenue-based taxes decreased $12 million, or 6%, to $186 million in 2008. Of the decrease, $8 million was attributable to the ten additional days in the 2007 period. A decrease in state franchise taxes of $9 million due to the 2007 enactment of the Texas margin tax, which is accounted for as an income tax, was partially offset by a $5 million increase in local franchise fees reflecting increased volumes of electricity delivered. Local franchise fees resulting from the 2006 cities rate settlement totaled $7 million for the nine months ended September 30, 2008 and $5 million for the period from January 1, 2007 through October 10, 2007.
Other income totaled $34 million in 2008 and $3 million in 2007. The 2008 amount reflected accretion of an adjustment (discount) to regulatory assets resulting from purchase accounting.
Other deductions totaled $17 million in 2008 and $27 million in 2007. The 2008 amount includes:
| • | $13 million in costs as a result of the 2006 settlement with certain cities related to rates, and |
| • | $3 million in equity losses (representing amortization expense) related to the ownership interest in an EFH Corp. subsidiary holding computer software. |
The 2007 amount includes:
| • | $20 million in costs a result of the 2006 cities rate settlement; |
| • | $3 million in costs related to a cancelled joint venture arrangement, and |
| • | $2 million in equity losses (representing amortization expense) related to the ownership interest in an EFH Corp. subsidiary. |
Interest income decreased $10 million, or 23%, to $34 million in 2008. The decrease reflected $4 million in lower earnings on assets held for certain employee benefit plans, a $3 million decrease in reimbursement of transition bond interest from TCEH and $2 million attributable to the ten additional days in the 2007 period.
Interest expense decreased $13 million, or 5%, to $229 million in 2008. The decrease reflected $9 million attributable to the ten additional days in the 2007 period.
Income tax expense totaled $180 million in 2008 compared to $160 million in 2007. The effective income tax rate decreased to 36.8% in 2008 from 37.6% in 2007. The decrease in the effective rate was primarily driven by a decrease in the benefit from the Medicare subsidy for post-employment benefits.
Net income increased $44 million, or 17%, to $309 million driven by increased revenues and higher other income, which reflects the effects of purchase accounting.
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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 “fair value adjustments”, “other activity” and “reclassification” as described below, represent the pretax effect on earnings of positions in the commodity contract portfolio that are marked-to-market in net income (see Note 18 to Financial Statements). The portfolio consists primarily of economic hedges but also includes trading positions.
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | October 11, 2007 through December 31, 2007 | January 1, 2007 through October 10, 2007 | |||||||||||||||
Commodity contract net asset (liability) at beginning of period | $ | 430 | $ | (1,917 | ) | $ | (920 | ) | $ | (23 | ) | |||||||
Settlements of positions (a) | (518 | ) | 39 | (87 | ) | (55 | ) | |||||||||||
Changes in fair value (b) | 1,741 | 2,294 | (1,469 | ) | (757 | ) | ||||||||||||
Fair value adjustments at Merger closing date (c) | — | — | 144 | — | ||||||||||||||
Reclassification at Merger closing date (d) | — | — | 400 | — | ||||||||||||||
Other activity (e) | 65 | 14 | 15 | (85 | ) | |||||||||||||
Commodity contract net asset (liability) at end of period (f) | $ | 1,718 | $ | 430 | $ | (1,917 | ) | $ | (920 | ) | ||||||||
| (a) | Represents reversals of previously recognized unrealized gains and losses upon settlement (offsets realized gains and losses recognized in the settlement period). |
| (b) | Represents unrealized gains and losses recognized, primarily related to positions in the long-term hedging program (see discussion above under “Long-Term Hedging Program”). Includes gains and losses recorded at contract inception dates (see Note 18 to the Financial Statements). |
| (c) | Represents purchase accounting adjustments arising primarily from the adoption of fair value accounting (largely nonperformance risk effect). |
| (d) | Represents reclassification of fair values of derivatives previously accounted for as cash flow hedges. |
| (e) | These amounts do not represent unrealized gains or losses. Includes initial values of positions involving the receipt or payment of cash or other consideration, generally related to options purchased/sold and physical natural gas exchange transactions. Activity in 2009 included $36 million for the net payment of option premiums, $29 million in natural gas provided under physical gas exchange transactions and $18 million in amortization of derivative liabilities related to settlement of certain multi-year power sales agreements (see Note 18 to Financial Statements), partially offset by $18 million for expired option premiums. Activity in the 2007 Predecessor period included $257 million (net of amounts settled of $7 million) in liabilities related to certain power sales agreements, net of a $102 million payment related to a structured economic hedge transaction in the long-term hedging program and $64 million in natural gas provided under physical gas exchange transactions. |
| (f) | 2009 amount excludes $4 million in net derivative liabilities related to cash flow hedge positions not marked-to-market in net income. |
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In addition to the effect on net income of recording unrealized mark-to-market gains and losses that are reflected in the table above, similar effects arise in the recording of unrealized ineffectiveness gains and losses associated with commodity-related positions accounted for as cash flow hedges. These effects on net income, which include reversals of previously recorded unrealized ineffectiveness gains and losses to offset realized gains and losses upon settlement, are reflected in the balance sheet as changes in cash flow hedge and other derivative assets and liabilities (see Note 18 to Financial Statements). The total pretax effect of recording unrealized gains and losses in net income related to commodity contracts is summarized as follows:
| Successor | Predecessor | ||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | October 11, 2007 through December 31, 2007 | January 1, 2007 through October 10, 2007 | ||||||||||||||
Unrealized gains (losses) related to contracts marked-to-market | $ | 1,223 | $ | 2,333 | $ | (1,556 | ) | $ | (812 | ) | |||||||
Ineffectiveness gains (losses) related to cash cash flow hedges | 2 | (4 | ) | — | 90 | ||||||||||||
Total unrealized gains (losses) related to commodity contracts | $ | 1,225 | $ | 2,329 | $ | (1,556 | ) | $ | (722 | ) | |||||||
Maturity Table — The following table presents the net commodity contract asset arising from recognition of fair values under mark-to-market accounting as of December 31, 2009, scheduled by the source of fair value and contractual settlement dates of the underlying positions.
| Maturity dates of unrealized commodity contract asset at December 31, 2009 | ||||||||||||||||||||
Source of fair value | Less than 1 year | 1-3 years | 4-5 years | Excess of 5 years | Total | |||||||||||||||
Prices actively quoted | $ | (63 | ) | $ | (92 | ) | $ | — | $ | — | $ | (155 | ) | |||||||
Prices provided by other external sources | 745 | 904 | 143 | — | 1,792 | |||||||||||||||
Prices based on models | 39 | (7 | ) | 227 | (178 | ) | 81 | |||||||||||||
Total | $ | 721 | $ | 805 | $ | 370 | $ | (178 | ) | $ | 1,718 | |||||||||
Percentage of total fair value | 42 | % | 47 | % | 21 | % | (10 | )% | 100 | % | ||||||||||
The “prices actively quoted” category reflects only exchange traded contracts for which active quotes are readily available. The “prices provided by other external sources” category represents forward commodity positions valued using prices for which over-the-counter broker quotes are available in active markets. Over-the-counter quotes for power in ERCOT that are deemed active markets (excluding the West zone) generally extend through 2012 and over-the-counter quotes for natural gas generally extend through 2015, depending upon delivery point. The “prices based on models” category contains the value of all nonexchange traded options, valued using option pricing models. In addition, this category contains other contractual arrangements that may have both forward and option components, as well as other contracts that are valued using proprietary long-term pricing models that utilize certain market based inputs. See Note 16 to 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):
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Net increase (decrease) in fair value of cash flow hedges: | ||||||||||||||||||
Commodities | $ | (20 | ) | $ | (8 | ) | $ | 5 | $ | (288 | ) | |||||||
Financing – interest rate swaps | — | (175 | ) | (182 | ) | — | ||||||||||||
| (20 | ) | (183 | ) | (177 | ) | (288 | ) | |||||||||||
Derivative value net losses (gains) reported in net income that relate to hedged transactions recognized in the period: | ||||||||||||||||||
Commodities | 11 | 11 | — | (95 | ) | |||||||||||||
Financing – interest rate swaps | 119 | 111 | — | 6 | ||||||||||||||
| 130 | 122 | — | (89 | ) | ||||||||||||||
Total income (loss) effect of cash flow hedges reported in other comprehensive income | $ | 110 | $ | (61 | ) | $ | (177 | ) | $ | (377 | ) | |||||||
All amounts included in accumulated other comprehensive income as of October 10, 2007, which totaled $34 million in net gains, were eliminated as part of purchase accounting.
We have historically used, and expect to continue to use, derivative instruments that are effective in offsetting future cash flow variability in interest rates and energy commodity prices. Amounts in accumulated other comprehensive income include the value of dedesignated and terminated cash flow hedges at the time of such dedesignation/termination, less amounts reclassified to earnings as the original hedged transactions are recognized, unless the hedged transactions become probable of not occurring. The effects of the hedge will be recorded in the statement of income as the hedged transactions are actually settled and affect earnings. Also see Note 18 to Financial Statements.
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FINANCIAL CONDITION
Liquidity and Capital Resources
Consolidated Cash Flows —Cash flows from operating, financing and investing activities included:
| Successor | Predecessor | |||||||||||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Three Months Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Nine Months Ended September 30, 2008 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||||||||
Cash flows — operating activities | ||||||||||||||||||||||||||
Income (loss) from continuing operations | $ | 408 | $ | (9,998 | ) | $ | (9,015 | ) | $ | (1,361 | ) | $ | (983 | ) | $ | 699 | ||||||||||
Adjustments to reconcile income (loss) from continuing operations to cash provided by (used in) operating activities: | ||||||||||||||||||||||||||
Depreciation and amortization | 2,172 | 2,070 | 516 | 568 | 1,554 | 684 | ||||||||||||||||||||
Deferred income tax expense (benefit) – net | 253 | (477 | ) | (44 | ) | (736 | ) | (433 | ) | (111 | ) | |||||||||||||||
Impairment charges | 124 | 10,071 | 9,570 | — | 501 | — | ||||||||||||||||||||
Increase of toggle notes in lieu of cash interest | 511 | — | — | — | — | — | ||||||||||||||||||||
Net charges related to cancelled development of generation facilities | — | — | — | 2 | — | 676 | ||||||||||||||||||||
Unrealized net (gains) losses from mark-to-market valuations of commodity positions | (1,225 | ) | (2,329 | ) | (2,550 | ) | 1,556 | 221 | 722 | |||||||||||||||||
Unrealized net (gains) losses from mark-to-market valuations of interest rate swaps | (696 | ) | 1,477 | 1,512 | — | (36 | ) | — | ||||||||||||||||||
Other, net | 196 | 182 | 55 | 16 | 128 | 52 | ||||||||||||||||||||
Changes in operating assets and liabilities (including margin deposits) | (32 | ) | 509 | 504 | (495 | ) | 5 | (457 | ) | |||||||||||||||||
Cash provided by (used in) operating activities | $ | 1,711 | $ | 1,505 | $ | 548 | $ | (450 | ) | $ | 957 | $ | 2,265 | |||||||||||||
Cash flows — financing activities | ||||||||||||||||||||||||||
Equity financing from Sponsor Group and other investors | $ | — | $ | — | $ | — | $ | 8,236 | $ | — | $ | — | ||||||||||||||
Net issuances, repayments and repurchases of borrowings | 458 | 1,537 | (1,468 | ) | 26,615 | 3,005 | 2,304 | |||||||||||||||||||
Net proceeds from sale of noncontrolling interests | — | 1,253 | 1,253 | — | — | — | ||||||||||||||||||||
Common stock dividends paid | — | — | — | — | — | (788 | ) | |||||||||||||||||||
Debt discount, financing and reacquisition expenses | (49 | ) | (21 | ) | (2 | ) | (986 | ) | (19 | ) | (17 | ) | ||||||||||||||
Other, net | 13 | 68 | 2 | — | 66 | (105 | ) | |||||||||||||||||||
Cash provided by (used in) financing activities | $ | 422 | $ | 2,837 | $ | (215 | ) | $ | 33,865 | $ | 3,052 | $ | 1,394 | |||||||||||||
Cash flows — investing activities | ||||||||||||||||||||||||||
Acquisition of EFH Corp. | $ | — | $ | — | $ | — | $ | (32,694 | ) | $ | — | $ | — | |||||||||||||
Capital expenditures, including purchases of mining-related assets and nuclear fuel | (2,545 | ) | (3,015 | ) | (810 | ) | (716 | ) | (2,205 | ) | (2,542 | ) | ||||||||||||||
Investment posted with derivative counterparty | (400 | ) | — | — | — | — | — | |||||||||||||||||||
Reduction of (proceeds from) TCEH senior secured letter of credit facility deposited with bank | 115 | — | — | (1,250 | ) | — | — | |||||||||||||||||||
Other, net | 197 | 81 | 250 | 97 | (169 | ) | 259 | |||||||||||||||||||
Cash used in investing activities | $ | (2,633 | ) | $ | (2,934 | ) | $ | (560 | ) | $ | (34,563 | ) | $ | (2,374 | ) | $ | (2,283 | ) | ||||||||
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Year Ended December 31, 2009 Compared to Year Ended December 31, 2008 —Cash provided by operating activities totaled $1.711 billion in 2009 compared to $1.505 billion in 2008. The $206 million increase reflected:
| • | a $489 million decrease in cash interest paid due to the payment of approximately $465 million of interest with an increase in toggle notes instead of cash as discussed under “Toggle Notes Interest Election” below, and |
| • | a $57 million favorable impact of timing of advanced metering surcharges, |
partially offset by a $347 million decrease in net margin deposits received primarily due to the effects of forward natural gas prices on positions in the long-term hedging program.
Three Months Ended December 31, 2008 Compared to Successor Period from October 11, 2007 through December 31, 2007 –Cash provided by operating activities totaled $548 million in the three months ended December 31, 2008 compared to cash used in operating activities of $450 million in the Successor period from October 11, 2007 through December 31, 2007. The $998 million increase reflects a $1.445 billion favorable change in net margin deposits primarily due to the effect of lower forward natural gas prices on positions in the long-term hedging program and a $143 million favorable change in income taxes paid due to a refund received in 2008, partially offset by a $737 million increase in cash interest payments.
Nine Months Ended September 30, 2008 Compared to Predecessor Period from January 1, 2007 through October 10, 2007 - Cash provided by operating activities totaled $957 million in the nine months ended September 30, 2008 compared to $2.265 billion in the Predecessor period from January 1, 2007 through October 10, 2007. The $1.308 billion decrease reflected a $1.588 billion increase in cash interest payments, partially offset by a $333 million favorable change in margin deposits primarily due to the effect of lower forward natural gas prices on hedge positions.
The decline in capital spending for the year ended December 31, 2009 as compared to the year ended December 31, 2008 primarily reflected a decrease in spending related to the construction of new generation facilities, which is nearing completion, partially offset by capital expenditures in the regulated business for advanced metering deployment and CREZ. Capital expenditures in 2009 totaled $1.324 billion in the Competitive Electric segment and $998 million in the Regulated Delivery segment.
Depreciation and amortization expense reported in the statement of cash flows exceeded the amount reported in the statement of income by $418 million, $460 million, $123 million, $153 million, $337 million and $50 million for the years ended December 31, 2009 and December 31, 2008, the three months ended December 31, 2008, the period from October 11, 2007 through December 31, 2007, the nine months ended September 30, 2008 and the Predecessor period from January 1, 2007 through October 10, 2007, respectively. For the 2007 Predecessor period, this difference represented amortization of nuclear fuel, which is reported as fuel costs in the statement of income consistent with industry practice. For the 2009, 2008 and 2007 Successor periods, this difference also represented amortization of intangible net assets and debt fair value discounts arising from purchase accounting that is reported in various other income statement line items including operating revenues, fuel and purchased power costs, other income and interest expense.
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Debt Financing Activity—Activities related to short-term borrowings and long-term debt during the year ended December 31, 2009 are as follows (all amounts presented are principal, and repayments and repurchases, including exchanges, include amounts related to capital leases and exclude amounts related to debt discount, financing and reacquisition expenses):
| Borrowings (a) | Repayments and Repurchases(b) | |||||
TCEH | $ | 739 | $ | 415 | ||
EFC Holdings | — | 7 | ||||
Intermediate Holding | 141 | — | ||||
EFH Corp. | 424 | 227 | ||||
Oncor | — | 104 | ||||
Total long-term | 1,304 | 753 | ||||
TCEH | 53 | — | ||||
Oncor | 279 | — | ||||
Total short-term (c) | 332 | — | ||||
Total | $ | 1,636 | $ | 753 | ||
(a) Includes $782 million of noncash principal increases consisting of: $309 million of EFH Corp. Toggle Notes and $202 million of TCEH Toggle Notes in May and November 2009 in payment of accrued interest as discussed below under “Toggle Notes Interest Election,” $256 million of EFH Corp. and EFIH notes issued in debt exchanges as discussed in Note 12 to Financial Statements and $15 million related to capital leases. (b) Includes $357 million of noncash retirements as a result of debt exchanges discussed in Note 12 to Financial Statements. (c) Short-term amounts represent net borrowings/repayments. | ||||||
See Note 12 to Financial Statements for further detail of long-term debt and other financing arrangements.
We, our affiliates or our agents may from time to time purchase our outstanding debt securities for cash in open market purchases or privately negotiated transactions or pursuant to a Section 10b-5(1) plan, or we may refinance existing debt securities. We will evaluate any such transactions in light of market prices of the securities, taking into account liquidity requirements and prospects for future access to capital, contractual restrictions and other factors. The amounts involved in any such transactions, individually or in the aggregate, may be material. See Note 12 to Financial Statements for discussion of debt exchange offers completed in November 2009.
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Available Liquidity — The following table summarizes changes in available liquidity for the year ended December 31, 2009.
| Available Liquidity | ||||||||||
| December 31, 2009 | December 31, 2008 | Change | ||||||||
Cash and cash equivalents, excluding Oncor | $ | 1,161 | $ | 1,564 | $ | (403 | ) | |||
Investments held in money market fund | — | 142 | (142 | ) | ||||||
TCEH Delayed Draw Term Loan Facility | — | 522 | (522 | ) | ||||||
TCEH Revolving Credit Facility (a) | 1,721 | 1,767 | (46 | ) | ||||||
TCEH Letter of Credit Facility | 399 | 490 | (91 | ) | ||||||
Subtotal | $ | 3,281 | $ | 4,485 | $ | (1,204 | ) | |||
Short-term investment (b) | 490 | — | 490 | |||||||
Total liquidity, excluding Oncor (c) | $ | 3,771 | $ | 4,485 | $ | (714 | ) | |||
Cash and cash equivalents – Oncor | $ | 28 | $ | 125 | $ | (97 | ) | |||
Oncor Revolving Credit Facility | 1,262 | 1,508 | (246 | ) | ||||||
Total Oncor liquidity | $ | 1,290 | $ | 1,633 | $ | (343 | ) | |||
| (a) | As of December 31, 2009 and 2008, the TCEH Revolving Credit Facility includes $141 million and $144 million, respectively, of commitments from Lehman that are only available from the fronting banks and the swingline lender. |
| (b) | Includes $425 million cash investment (including accrued interest) and $65 million in letters of credit posted related to certain interest rate and commodity hedge transactions. Under the related agreement, the collateral is to be returned no later than March 2010. See Note 18 to Financial Statements. |
| (c) | Pursuant to PUCT rules, TCEH is required to maintain available liquidity to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at December 31, 2009, the total availability under the TCEH credit facilities should be further reduced by $228 million. See “Regulation and Rates – Certification of REPs.” |
Note: Available liquidity above does not include the amounts available from exercising the payment-in-kind (PIK) option on the EFH Corp. Toggle Notes and TCEH Toggle Notes, which for the remaining payment dates from May 2010 through November 2012 could avoid cash interest payments of approximately $1.6 billion.
The $714 million decrease in available liquidity excluding Oncor, after taking into account the short-term investment, was driven by capital spending to construct the new generation facilities.
The decrease in available liquidity for Oncor of $343 million in the year ended December 31, 2009 reflected ongoing capital investment in transmission and distribution infrastructure.
See Note 12 to Financial Statements for additional discussion of these credit facilities.
The net proceeds from the January 2010 issuance of $500 million principal amount of senior secured notes (described in Note 12 to Financial Statements) increased available liquidity.
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Pension and OPEB Plan Funding— Pension and OPEB plan funding is expected to total $45 million and $24 million, respectively, in 2010. Based on the funded status of the pension plan at December 31, 2009, funding is expected to total approximately $750 million for the 2010 to 2014 period. Oncor is expected to fund approximately 75% of this amount consistent with its share of the pension liability. We made pension and OPEB contributions of $109 million and $22 million, respectively, in 2009 including transfers of investments related to the salary deferral and supplemental retirement plans totaling $31 million.
See Note 21 to Financial Statements for more information regarding the pension and OPEB plans, including the funded status of the plans as of December 31, 2009.
Toggle Notes Interest Election — EFH Corp. and TCEH have the option every six months at their discretion, ending with the payment due November 2012, to use the payment-in-kind (PIK) feature of their respective toggle notes in lieu of making cash interest payments. We elected to do so for the May 2009, November 2009 and May 2010 interest payments as an efficient and cost-effective method to further enhance liquidity, in light of the weaker economy and related lower electricity demand and the continuing uncertainty in the financial markets. Once EFH Corp. and/or TCEH make a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. and/or TCEH revoke the applicable election. Use of the PIK feature will be evaluated at each election period, taking into account market conditions and other relevant factors at such time.
EFH Corp. made its May and November 2009 interest payments and will make its May 2010 interest payment by using the PIK feature of the its Toggle Notes. During the applicable interest periods, the interest rate on the notes is increased from 11.25% to 12.00%. EFH Corp. increased the aggregate principal amount of the notes by $150 million and $159 million in May and November 2009, respectively, and will further increase the aggregate principal amount of the notes by $168 million in May 2010. The elections increased liquidity in 2009 by an amount equal to approximately $290 million and will further increase liquidity in May 2010 by an amount equal to approximately $157 million, with such amounts constituting the amount of cash interest that otherwise would have been payable on the notes. If paid in cash, the annual interest expense would increase by approximately $54 million, constituting the additional cash interest that would be payable with respect to the $477 million of additional principal amount. See Note 12 to Financial Statements for discussion of debt exchange offers that resulted in redemption of portions of the outstanding principal of these notes.
Similarly, TCEH made its May and November 2009 interest payments and will make its May 2010 interest payment by using the PIK feature of the its Toggle Notes. During the applicable interest periods, the interest rate on the notes is increased from 10.50% to 11.25%. TCEH increased the aggregate principal amount of the notes by approximately $98.5 million and $104 million in May and November 2009, respectively, and will further increase the aggregate principal amount of the notes by approximately $110 million in May 2010. The elections increased liquidity in 2009 by an amount equal to approximately $189 million and will further increase liquidity in May 2010 by an amount equal to approximately $103 million, with such amounts constituting the amount of cash interest that otherwise would have been payable on the notes. If paid in cash, the annual interest expense would increase by approximately $33 million, constituting the additional interest that would be payable with respect to the $312 million of additional principal amount.
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Liquidity Needs, IncludingCapital Expenditures —Capital expenditures, including capitalized interest, for 2010 are expected to total approximately $1.950 billion and include:
| • | $1.0 billion for investment in Oncor’s transmission and distribution infrastructure, including $216 million for Oncor’s investment related to the CREZ Transmission Plan; |
| • | $900 million for investments in TCEH generation facilities, including approximately: |
| • | $700 million for major maintenance, primarily in existing generation operations; |
| • | $150 million related to completion of the construction of a second generation unit and mine development at Oak Grove, and |
| • | $50 million for environmental expenditures related to existing generation units, and |
| • | $50 million for information technology and other corporate investments. |
We expect cash flows from operations combined with availability under our credit facilities discussed in Note 12 to Financial Statements to provide sufficient liquidity to fund our current obligations, projected working capital requirements, any restructuring obligations and capital spending for a period that includes the next twelve months.
Liquidity Effects of Commodity Hedging and Trading Activities — Commodity hedging and trading transactions typically require a counterparty to post collateral if the forward price of the underlying commodity moves such that the hedging or trading instrument held by such counterparty has declined in value. TCEH uses cash, letters of credit, asset-backed liens and other forms of credit support to satisfy such collateral obligations. In addition, TCEH’s Commodity Collateral Posting Facility, an uncapped senior secured revolving credit facility, funds the cash collateral posting requirements for a significant portion of the positions in the long-term hedging program not otherwise secured by a first-lien in the assets of TCEH. The aggregate principal amount of this facility is determined by the exposure arising from higher forward market prices, regardless of the amount of such exposure, on a portfolio of certain natural gas hedging transaction volumes. Including those hedging transactions where margin deposits are covered by unlimited borrowings under the TCEH Commodity Collateral Posting Facility, at December 31, 2009, more than 95% of the long-term natural gas hedging program transactions were secured by a first-lien interest in the assets of TCEH that is pari passu with the TCEH Senior Secured Facilities, the effect of which is a significant reduction in the liquidity exposure associated with collateral requirements for those hedging transactions. See Note 12 to Financial Statements for more information about this facility.
As of December 31, 2009, TCEH received or posted cash and letters of credit for commodity hedging and trading activities as follows:
| • | $183 million in cash has been posted with counterparties for exchange cleared transactions (including initial margin), as compared to $317 million posted as of December 31, 2008; |
| • | $516 million in cash has been received from counterparties, net of $4 million in cash posted, for over-the-counter and other non-exchange cleared transactions, as compared to $402 million received, net of $122 million in cash posted, as of December 31, 2008; |
| • | $379 million in letters of credit have been posted with counterparties, as compared to $342 million posted as of December 31, 2008, and |
| • | $44 million in letters of credit have been received from counterparties, as compared to $30 million received as of December 31, 2008. |
In addition, EFH Corp. (parent) elected to post cash collateral of $400 million in 2009 related to certain TCEH interest rate and commodity hedge transactions (see Note 18 to Financial Statements).
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With respect to exchange cleared transactions, these transactions typically require initial margin (i.e., the upfront cash and/or letter of credit posted to take into account the size and maturity of the positions and credit quality) in addition to variance margin (i.e., the daily cash margin posted to take into account changes in the value of the underlying commodity). The amount of initial margin required is generally defined by exchange rules. Clearing agents, however, typically have the right to request additional initial margin based on various factors including market depth, volatility and credit quality, which may be in the form of cash, letters of credit, a guaranty or other forms as negotiated with the clearing agent. With respect to cash collateral that is received, such cash collateral is either used for working capital and other corporate purposes, including reducing short-term borrowings under credit facilities, or it is required to be deposited in a separate account and restricted from being used for working capital and other corporate purposes. With respect to over-the-counter transactions, counterparties generally have the right to substitute letters of credit for such cash collateral. In such event, the cash collateral previously posted would be returned to such counterparties thereby reducing liquidity in the event that it was not restricted. As of December 31, 2009, restricted cash collateral held totaled $1 million. See Note 25 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, 2009, approximately 600 million MMBtu of positions related to the long-term hedging program were not directly secured on an asset-lien basis and thus have cash collateral posting requirements. The uncapped TCEH Commodity Collateral Posting Facility supports the collateral posting requirements related to these transactions.
Interest Rate Swap Transactions —See Note 12 to Financial Statements for TCEH interest rate swaps entered into as of December 31, 2009.
Distributions from Oncor —Until December 31, 2012, distributions paid by Oncor to its members are limited to an amount not to exceed Oncor’s net income determined in accordance with GAAP, subject to certain defined adjustments. Distributions are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity.
In January 2009, the PUCT awarded approximately $1.3 billion of Competitive Renewable Energy Zone (CREZ) construction projects to Oncor. See discussion below under “Regulation and Rates – Oncor Matters with the PUCT.” As a result of the increased capital expenditures for CREZ and the debt-to-equity ratio cap, we expect that Oncor may retain all or a portion of its available cash to fund such construction instead of paying distributions.
Income Tax Refunds/Payments —Income tax payments, primarily amounts related to the Texas margin tax, are expected to total approximately $75 million in the next 12 months. In 2009, we received a refund totaling $98 million in income taxes and related interest related to IRS audits of 1993 and 1994 income tax returns and made net payments totaling approximately $44 million related to the Texas margin tax. In 2008, we received net federal income tax refunds of $229 million, including $98 million related to 2007 tax payments and $142 million related to a net operating loss carryback to the 2006 tax year. Federal income tax payments totaled $257 million in 2007.
As discussed in Note 8 to 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 2010.
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Sale of Accounts Receivable — TXU Energy participates in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with transfers and servicing accounting standards. Under the program, TXU Energy (originator) sells retail trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp., which sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions. All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Funding under the program totaled $383 million and $416 million at December 31, 2009 and 2008, respectively. See Note 1 to Financial Statements for discussion of a new accounting standard that is expected to require consolidation of this program and Note 11 to Financial Statements for a more complete description of the program including the impact of the program on the financial statements for the periods presented and the contingencies that could result in termination of the program and a reduction of liquidity should the underlying financing be settled.
Capitalization — Our capitalization ratios consisted of 104.6% and 106.0% long-term debt, less amounts due currently, and (4.6)% and (6.0)% common stock equity, at December 31, 2009 and 2008, respectively. Total debt to capitalization, including short-term debt, was 104.4% and 105.8% at December 31, 2009 and 2008, respectively.
Financial Covenants, Credit Rating Provisions and Cross Default Provisions — The terms of certain of our financing arrangements contain maintenance covenants with respect to leverage ratios and/or minimum net worth. As of December 31, 2009, we were in compliance with all such maintenance covenants.
Covenants and Restrictions under Financing Arrangements — Each of the TCEH Senior Secured Facilities and the indentures governing substantially all of the debt we have issued in connection with, and subsequent to, the Merger contain covenants that could have a material impact on the liquidity and operations of EFH Corp. and its subsidiaries.
Adjusted EBITDA (as used in the restricted payments covenant contained in the indenture governing the EFH Corp. Senior Notes) for the year ended December 31, 2009 totaled $4.857 billion for EFH Corp. See Exhibit 99(b) and 99(c) for a reconciliation of net income to Adjusted EBITDA for EFH Corp. and TCEH, respectively, for the years ended December 31, 2009 and 2008.
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The following table summarizes TCEH’s secured debt to adjusted EBITDA ratio under the maintenance covenant in the TCEH Senior Secured Facilities and various other financial ratios of EFH Corp., Intermediate Holding and TCEH that are applicable under certain other covenants in the TCEH Senior Secured Facilities and the indentures governing the TCEH Senior Notes, the EFH Corp. Senior Notes, the EFH Corp. 9.75% Notes and the EFIH Notes as of December 31, 2009 and 2008 and the corresponding maintenance and other covenant threshold levels as of December 31, 2009:
| December 31, 2009 | December 31, 2008 | Threshold Level as of December 31, 2009 | ||||
Maintenance Covenant: | ||||||
TCEH Senior Secured Facilities: | ||||||
Secured debt to adjusted EBITDA ratio | 4.76 to 1.00 | 4.77 to 1.00 | Must not exceed 7.25 to 1.00 (a) | |||
Debt Incurrence Covenants: | ||||||
EFH Corp. Senior Notes: | ||||||
EFH Corp. fixed charge coverage ratio | 1.2 to 1.0 | 1.5 to 1.0 | At least 2.0 to 1.0 | |||
TCEH fixed charge coverage ratio | 1.5 to 1.0 | 1.3 to 1.0 | At least 2.0 to 1.0 | |||
EFH Corp. 9.75% Notes: | ||||||
EFH Corp. fixed charge coverage ratio | 1.2 to 1.0 | N/A | At least 2.0 to 1.0 | |||
TCEH fixed charge coverage ratio | 1.5 to 1.0 | N/A | At least 2.0 to 1.0 | |||
EFIH Notes: | ||||||
Intermediate Holding fixed charge coverage ratio (b) | 53.8 to 1.0 | N/A | At least 2.0 to 1.0 | |||
TCEH Senior Notes: | ||||||
TCEH fixed charge coverage ratio | 1.5 to 1.0 | 1.3 to 1.0 | At least 2.0 to 1.0 | |||
TCEH Senior Secured Facilities: | ||||||
TCEH fixed charge coverage ratio | 1.5 to 1.0 | 1.3 to 1.0 | At least 2.0 to 1.0 | |||
Restricted Payments/Limitations on Investments Covenants: | ||||||
EFH Corp. Senior Notes: | ||||||
General restrictions (non-Sponsor Group payments): | ||||||
EFH Corp. fixed charge coverage ratio (c) | 1.4 to 1.0 | 1.3 to 1.0 | At least 2.0 to 1.0 | |||
General restrictions (Sponsor Group payments): | ||||||
EFH Corp. fixed charge coverage ratio (c) | 1.2 to 1.0 | 1.5 to 1.0 | At least 2.0 to 1.0 | |||
EFH Corp. leverage ratio | 9.4 to 1.0 | 6.9 to 1.0 | Equal to or less than 7.0 to 1.0 | |||
EFH Corp. 9.75% Notes: | ||||||
General restrictions (non-Sponsor Group payments): | ||||||
EFH Corp. fixed charge coverage ratio (c) | 1.4 to 1.0 | N/A | At least 2.0 to 1.0 | |||
General restrictions (Sponsor Group payments): | ||||||
EFH Corp. fixed charge coverage ratio (c) | 1.2 to 1.0 | N/A | At least 2.0 to 1.0 | |||
EFH Corp. leverage ratio | 9.4 to 1.0 | N/A | Equal to or less than 7.0 to 1.0 | |||
EFIH Notes: | ||||||
General restrictions (non-EFH Corp. payments): | ||||||
Intermediate Holding fixed charge coverage | 3.9 to 1.0 | N/A | At least 2.0 to 1.0 | |||
General restrictions (EFH Corp. payments): | ||||||
Intermediate Holding fixed charge coverage | 53.8 to 1.0 | N/A | At least 2.0 to 1.0 | |||
Intermediate Holding leverage ratio | 4.4 to 1.0 | N/A | Equal to or less than 6.0 to 1.0 | |||
TCEH Senior Notes: | ||||||
TCEH fixed charge coverage ratio | 1.5 to 1.0 | 1.3 to 1.0 | At least 2.0 to 1.0 | |||
TCEH Senior Secured Facilities: | ||||||
Payments to Sponsor Group: | ||||||
TCEH total debt to adjusted EBITDA ratio | 8.4 to 1.0 | 8.7 to 1.0 | At least 6.5 to 1.0 | |||
| (a) | Threshold level decreases to a maximum of 7.00 to 1.00 effective March 31, 2010 and to a maximum of 6.75 to 1.00 effective December 31, 2010. Calculation excludes debt that ranks junior to the TCEH Senior Secured Facilities. |
| (b) | Although Intermediate Holding currently meets the fixed charge coverage ratio threshold applicable to certain covenants contained in the indenture governing the EFIH Notes, Intermediate Holding’s ability to use such thresholds to incur debt or make restricted payments/investments is currently limited by the covenants contained in the EFH Corp. Senior Notes and the EFH Corp. 9.75% Notes. |
| (c) | The EFH Corp. fixed charge coverage ratio for non-Sponsor Group payments includes the results of Oncor Holdings and its subsidiaries. The EFH Corp. fixed charge coverage ratio for Sponsor Group payments excludes the results of Oncor Holdings and its subsidiaries. |
| (d) | The Intermediate Holding fixed charge coverage ratio for non-EFH Corp. payments includes the results of Oncor Holdings and its subsidiaries. The Intermediate Holding fixed charge coverage ratio for EFH Corp. payments excludes the results of Oncor Holdings and its subsidiaries. |
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Credit Ratings —The issuer credit ratings as of January 31, 2010 for EFH Corp. and its subsidiaries, except for Oncor, are B-, Caa1 and B by S&P, Moody’s and Fitch, respectively. The issuer credit ratings, as of January 31, 2010, for Oncor are BBB+ and BBB- by S&P and Fitch, respectively.
Additionally, the rating agencies assign credit ratings on certain of our debt securities. The credit ratings assigned for these debt securities as of January 31, 2010 are presented below:
| S&P | Moody’s | Fitch | ||||
EFH Corp. (Senior Secured) (a) | B+ | Caa3 | B+ | |||
EFH Corp. (Senior Unsecured) (b) | B- | Caa3 | B | |||
EFH Corp. (Unsecured) | CCC | Caa3 | CCC | |||
Intermediate Holding (Senior Secured) | B+ | Caa3 | B+ | |||
EFC Holdings (Senior Unsecured) | CCC | Caa3 | CCC | |||
TCEH (Senior Secured) | B+ | B1 | BB | |||
TCEH (Senior Unsecured) (c) | CCC | Caa2 | B | |||
TCEH (Unsecured) | CCC | Caa3 | CCC | |||
Oncor (Senior Secured) (d) | BBB+ | Baa1 | BBB | |||
Oncor (Senior Unsecured) (d) | BBB+ | Baa1 | BBB- |
| (a) | EFH Corp. 9.75% Notes and EFH Corp. 10% Notes. |
| (b) | EFH Corp. 10.875% Notes and EFH Corp. Toggle Notes. |
| (c) | TCEH 10.25% Notes and TCEH Toggle Notes. |
| (d) | All of Oncor’s long-term debt is secured by a first priority lien and is considered senior secured debt. |
In November 2009, the credit rating agencies announced certain rating actions shortly after completion of the EFH Corp. debt exchange transaction discussed in Note 12 to Financial Statements. S&P restored its corporate issuer ratings of EFH Corp., EFC Holdings and TCEH with multi-notch upgrades to B- from SD and maintained a negative outlook. Also, S&P established B+ ratings for the new EFH Corp. 9.75% Notes and EFIH Notes, and it completed multi-notch upgrades from ratings of D for issuances subject to the exchange. Previously, in accordance with its “distressed exchange” policy, S&P downgraded the corporate issuer ratings of EFH Corp., EFC Holdings and TCEH to SD from CC and downgraded ratings of issuances subject to the exchange to D from CC. Moody’s affirmed its Caa1 corporate family rating and negative outlook for EFH Corp. and TCEH but upgraded its probability of default rating to Caa2 from Ca as it determined that the final transaction results did not represent a “distressed exchange.” In addition, Moody’s established Caa3 ratings for the new EFH Corp. 9.75% Notes and EFIH Notes and completed upgrades of certain securities due to results of the exchange. Fitch established a rating of B+ on the new EFH Corp. 9.75% Notes and EFIH Notes resulting from the exchange and downgraded its ratings of the EFH Corp. 10.875% and Toggle Notes by one notch to B from B+. Additionally, Fitch affirmed its ratings and outlook for EFH Corp., EFC Holdings and TCEH. The ratings and stable outlook for Oncor were unaffected by the exchange and were affirmed by all three agencies.
In June 2009, Moody’s upgraded the long-term debt rating for Oncor’s senior secured debt by two notches from Baa3 to Baa1 citing, among other things, Oncor’s position as a rate-regulated electric transmission and distribution utility in Texas, reasonably supportive regulatory jurisdiction, solid financial credit metrics, adequate sources of near-term liquidity and the continued evidence of strong corporate independence from EFH Corp. Moody’s ratings outlook for Oncor remains stable.
A rating reflects only the view of a rating agency, and is not a recommendation to buy, sell or hold securities. Ratings can be revised upward or downward at any time by a rating agency if such rating agency decides that circumstances warrant such a change.
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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, 2009, counterparties to those contracts could have required TCEH to post up to an aggregate of $41 million in additional collateral. This amount largely represents the below market terms of these contracts as of December 31, 2009; thus, this amount will vary depending on the value of these contracts on any given day.
Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s below investment grade credit rating, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. The amount of collateral support required to be posted, as well as the time period of transition charges covered, varies by utility. As of December 31, 2009, TCEH has posted collateral support in the form of letters of credit to the applicable utilities in an aggregate amount equal to $29 million, with $15 million of this amount posted for the benefit of Oncor.
The PUCT has rules in place to assure adequate credit worthiness of each REP, including the ability to return customer deposits, if necessary. Under these rules, as of December 31, 2009, TCEH maintained availability under its credit facilities of approximately $228 million. See “Regulation and Rates – Certification of REPs.”
The RRC has rules in place to assure adequate credit worthiness of parties that have mining reclamation obligations. Under these rules, should the RRC determine that the credit worthiness of Luminant Generation Company LLC (a subsidiary of TCEH) is not sufficient to support its reclamation obligations, TCEH may be required to post cash or letter of credit collateral support in an amount currently estimated to be approximately $600 million to $800 million. The actual amount (if required) could vary depending upon numerous factors, including Luminant Generation Company LLC’s credit worthiness and the level of mining reclamation obligations.
ERCOT also has rules in place to assure adequate credit worthiness of parties that schedule power on the ERCOT System. Under these rules, TCEH has posted collateral support, predominantly in the form of letters of credit, totaling $43 million as of December 31, 2009 (which is subject to weekly adjustments based on settlement activity with ERCOT).
Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As part of this stipulation, TCEH is required to post a letter of credit in an amount equal to $170 million to secure its payment obligations to Oncor if two or more rating agencies downgrade Oncor’s credit ratings below investment grade.
Other arrangements of EFH Corp. and its subsidiaries, including Oncor’s credit facility, the accounts receivable securitization program (see Note 11 to 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 sale of receivables program and hedging obligations, in an aggregate amount in excess of $200 million may result in a cross default under the TCEH Senior Secured Facilities. Under these facilities, such a default will allow the lenders to accelerate the maturity of outstanding balances ($22.357 billion at December 31, 2009) under such facilities.
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The indenture governing the TCEH Senior Notes contains a cross acceleration provision where a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of TCEH or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the TCEH Senior Notes.
Under the terms of a TCEH rail car lease, which had approximately $47 million in remaining lease payments as of December 31, 2009 and terminates in 2017, if TCEH failed to perform under agreements causing its indebtedness in aggregate principal amount of $100 million or more to become accelerated, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.
Under the terms of a TCEH rail car lease, which had approximately $53 million in remaining lease payments as of December 31, 2009 and terminates in 2028, if obligations of TCEH in excess of $200 million in the aggregate for payments of obligations to third party creditors under lease agreements, deferred purchase agreements or loan or credit agreements are accelerated prior to their original stated maturity, the lessor could, among other remedies, terminate the lease and effectively accelerate the payment of any remaining lease payments due under the lease.
The indentures governing the EFH Corp. Senior Notes, 9.75% and 10% Notes contain a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of EFH Corp. or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the EFH Corp. Senior Notes, 9.75% and 10% Notes.
The indenture governing the EFIH Notes contains a cross acceleration provision whereby a payment default at maturity or on acceleration of principal indebtedness under any instrument or instruments of Intermediate Holding or any of its restricted subsidiaries in an aggregate amount equal to or greater than $250 million may cause the acceleration of the EFIH Notes.
The accounts receivable securitization program contains a cross default provision with a threshold of $200 million that applies in the aggregate to the originator, any parent guarantor of an originator or any subsidiary acting as collection agent under the program. TXU Receivables Company and EFH Corporate Services Company (a direct subsidiary of EFH Corp.), as collection agent, in the aggregate have a cross default threshold of $50,000. If any of the aforementioned defaults on indebtedness of the applicable threshold were to occur, the program could terminate.
We enter into energy-related and financial contracts, the master forms of which contain provisions whereby an event of default or acceleration of settlement would occur if we were to default under an obligation in respect of borrowings in excess of thresholds, which vary, stated in the contracts. The subsidiaries whose default would trigger cross default vary depending on the contract.
Each of TCEH’s natural gas hedging agreements that are secured with a lien on its assets on a pari passu basis with the TCEH Senior Secured Facilities contains a cross default provision. In the event of a default by TCEH or any of its subsidiaries relating to indebtedness (such amounts varying by contract but ranging from $200 million to $250 million) that results in the acceleration of such debt, then each counterparty under these hedging agreements would have the right to terminate its hedge agreement with TCEH and require all outstanding obligations under such agreement to be settled.
In the event of a default by TCEH relating to indebtedness in an amount equal to or greater than $200 million that results in the acceleration of such debt, then each counterparty under TCEH’s interest rate swap agreements with an aggregate derivative liability of $1.21 billion at December 31, 2009 would have the right to terminate its interest rate swap agreement with TCEH and require all outstanding obligations under such agreement to be settled.
A default by Oncor or any subsidiary thereof in respect of indebtedness in a principal amount in excess of $50 million may result in a cross default under its credit facility. Under this facility such a default may cause the maturity of outstanding balances ($616 million at December 31, 2009) under such facility to be accelerated.
Other arrangements, including leases, have cross default provisions, the triggering of which would not be expected to result in a significant effect on liquidity.
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Long-Term Contractual Obligations and Commitments— The following table summarizes our contractual cash obligations as of December 31, 2009 (see Note 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) | $ | 340 | $ | 1,820 | $ | 22,817 | $ | 17,492 | $ | 42,469 | |||||
Long-term debt – interest (b) | 3,059 | 6,491 | 5,747 | 7,115 | 22,412 | ||||||||||
Operating and capital leases (c) | 146 | 149 | 114 | 330 | 739 | ||||||||||
Obligations under commodity purchase and services agreements (d) | 1,595 | 1,796 | 954 | 815 | 5,160 | ||||||||||
Total contractual cash obligations | $ | 5,140 | $ | 10,256 | $ | 29,632 | $ | 25,752 | $ | 70,780 | |||||
| (a) | Excludes capital lease obligations, unamortized discounts and fair value premiums and discounts related to purchase accounting. Also excludes $278 million of additional principal amount of notes to be issued in May 2010 and due in 2016 and 2017, reflecting the election of the PIK feature on toggle notes as discussed above under “Toggle Notes Interest Election.” |
| (b) | Includes net amounts payable under interest rate swaps. Variable interest payments and net amounts payable under interest rate swaps are calculated based on interest rates in effect at December 31, 2009. |
| (c) | Includes short-term noncancellable leases. |
| (d) | Includes capacity payments, nuclear fuel and natural gas take-or-pay contracts, coal contracts, business services and nuclear-related outsourcing and other purchase commitments. Amounts presented for variable priced contracts assumed the year-end 2009 price remained in effect for all periods except where contractual price adjustment or index-based prices were specified. |
The following are not included in the table above:
| • | contracts between affiliated entities and intercompany debt; |
| • | individual contracts that have an annual cash requirement of less than $1 million (however, multiple contracts with one counterparty that are more than $1 million on an aggregated basis have been included); |
| • | contracts that are cancellable without payment of a substantial cancellation penalty; |
| • | employment contracts with management; |
| • | estimated funding of pension plan totaling $45 million in 2010 and approximately $750 million for the 2010 to 2014 period as discussed above under “Pension and OPEB Plan Funding;” |
| • | liabilities related to uncertain tax positions totaling $1.6 billion discussed in Note 8 to Financial Statements as the ultimate timing of payment is not known, and |
| • | capital expenditures under PUCT orders (advanced meters and CREZ projects). |
Guarantees — See Note 13 to Financial Statements for details of guarantees.
OFF–BALANCE SHEET ARRANGEMENTS
See discussion above regarding sales of accounts receivable under “Financial Condition – Liquidity and Capital Resources” and in Note 11 to Financial Statements.
Also see Note 13 to Financial Statements regarding guarantees.
COMMITMENTS AND CONTINGENCIES
See Note 13 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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REGULATION AND RATES
Regulatory Investigations and Reviews
See Note 13 to Financial Statements.
Certification of REPs
In April 2009, the PUCT finalized a rule relating to the Certification of Retail Electric Providers. The rule strengthens the certification requirements for REPs in order to better protect customers, transmission and distribution utilities (TDUs), and other REPs from the potential insolvency of REPs. The rule, among other things, increases creditworthiness and financial reporting requirements for REPs and provides additional customer protection requirements and regulatory asset consideration for TDU bad debt expenses. Under the rule, Oncor uncollectible amounts owed by REPs are deferred as a regulatory asset. Recovery of the regulatory asset will be considered in a future rate case. Accordingly, Oncor recognized an approximately $3 million one-time reversal of bad debt expense in the three months ended June 30, 2009 (reported in other income). Due to the commitments made to the PUCT in connection with the Merger, Oncor may not recover bad debt expense, or certain other costs and expenses, from rate payers in the event of a TXU Energy default or bankruptcy. Under the rule, REPs are required to amend their certifications, including the manner in which they meet financial requirements, by May 21, 2010. TXU Energy plans to file its amended certification no later than the first quarter 2010. Under the new financial requirements, which will be effective upon approval of the amended certification, the amount of available liquidity required to be maintained by TCEH would have been reduced from $228 million as of December 31, 2009 to approximately $83 million as a result of no longer having to reserve liquidity for payments related to TDUs.
FERC Infrastructure Protection Standards
In September 2009, the FERC issued an order approving a revised set of mandatory NERC standards for critical infrastructure protection (CIP). These standards are designed to protect the nation’s bulk power system against potential disruptions from cyber security breaches. The mandatory reliability standards require certain users, owners and operators of the bulk power system to establish policies, plans and procedures to safeguard physical and electronic access to control systems, to train personnel on security matters, to report security incidents, and to be prepared to recover from a cyber incident. Both Oncor and Luminant were compliant at December 31, 2009 and are expected to achieve “Auditable Compliance” by year-end 2010 in accordance with the NERC CIP implementation schedule.
Wholesale Market Design – Nodal Market
In August 2003, the PUCT adopted a rule that, when implemented, will alter the wholesale market design in the ERCOT market. The rule requires ERCOT to:
| • | use a stakeholder process to develop a new wholesale market model; |
| • | operate a voluntary day-ahead energy market; |
| • | directly assign all congestion rents to the resources that caused the congestion; |
| • | use nodal energy prices for resources; |
| • | provide information for energy trading hubs by aggregating nodes; |
| • | use zonal prices for loads, and |
| • | provide congestion revenue rights (but not physical rights). |
ERCOT currently has a zonal wholesale market structure consisting of four geographic zones. The proposed location-based congestion-management market is referred to as a “nodal” market because wholesale pricing would differ across the various nodes on the transmission grid. The implementation of a nodal market is being done in conjunction with transmission improvements designed to reduce current congestion. Pursuant to a request from the PUCT, ERCOT announced in November 2008 a preliminary schedule for the implementation of the nodal market by December 2010.
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ERCOT imposes a surcharge on all Qualified Scheduling Entities in the ERCOT market (including subsidiaries of TCEH) for the purpose of financing 38% of ERCOT’s expected nodal implementation costs. In November 2008, ERCOT filed a request with the PUCT for approval of an interim increase in the nodal surcharge from $0.169 per MWh to $0.375 per MWh. In September 2009, the PUCT approved an increase in the nodal surcharge to $0.375 per MWh, effective January 1, 2010. At the approved $0.375 per MWh nodal surcharge, the annual surcharge to us will be an estimated $30 million to $35 million, which is reported in fuel, purchased power costs and delivery fees. The implementation of a nodal market is scheduled for December 2010. We cannot predict the ultimate impact of the proposed nodal wholesale market design on our operations or financial results.
Environmental Regulations
See discussion in Note 3 to Financial Statements regarding the invalidation of the EPA’s Clean Air Interstate Rule and the related impairment in 2008 of intangible assets representing NOx and SO2 emission allowances.
Oncor Matters with the PUCT
Stipulation Approved by the PUCT—In April 2008, the PUCT entered an order, which became final in June 2008, approving the terms of a stipulation relating to the filing in 2007 by Oncor and Texas Holdings of a Merger-related Joint Report and Application with the PUCT pursuant to Section 14.101(b) of PURA and PUCT Substantive Rule 25.75. The stipulation required the filing of a rate case by Oncor no later than July 1, 2008 based on a test year ended December 31, 2007. In July 2008, Nucor Steel filed an appeal of the PUCT’s order in the 200th District Court of Travis County, Texas. The parties to the appeal have agreed to a schedule that would result in a hearing in June 2010. Oncor was named a defendant and intends to vigorously defend the appeal. Oncor filed the rate case with the PUCT in June 2008, and the PUCT issued a final order with respect to the rate review in August 2009 as discussed below.
Rate Case — In June 2008, Oncor filed for a rate review with the PUCT and 204 cities. In August 2009, the PUCT issued a final order with respect to the rate review. The final order approves a total annual revenue requirement for Oncor of $2.64 billion, based on Oncor’s 2007 test year cost of service and customer characteristics. New rates were calculated for all customer classes using 2007 test year billing metrics and the approved class cost allocation and rate design. The PUCT staff has estimated that the final order results in an approximate $115 million increase in base rate revenues over Oncor’s 2007 adjusted test year revenues, before recovery of rate case expenses. Prior to implementing the new rates in September 2009, Oncor had already begun recovering $45 million of the $115 million increase as a result of approved transmission cost recovery factor and energy efficiency cost recovery factor filings, such as those discussed below. Also see Note 25 to Financial Statements regarding the PUCT’s review of regulatory assets and liabilities.
Key findings made by the PUCT in the rate review include:
| • | recognizing and affirming Oncor’s corporate ring-fence from EFH Corp. and its unregulated affiliates by rejecting a proposed consolidated tax savings adjustment arising out of EFH Corp.’s ability to offset Oncor’s taxable income against losses from other investments; |
| • | approving the recovery of all of Oncor’s capital investment in its transmission and distribution system, including investment in certain automated meters that will be replaced pursuant to Oncor’s advanced meter deployment plan; |
| • | denying recovery of $25 million of regulatory assets, which resulted in a $16 million after tax loss being recognized in the three months ended September 30, 2009, and |
| • | setting Oncor’s return on equity at 10.25%. |
New rates were implemented upon approval of new tariffs in September 2009. In November 2009, the PUCT issued an Order on Rehearing that established a new rate class but did not change the revenue requirements. In January 2010, the PUCT denied all Second Motions for Rehearing, which made the November 2009 Order on Rehearing final and appealable.
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Advanced Meter Rulemaking — In 2005, the Texas Legislature passed legislation that authorized electric utilities to implement a surcharge to recover costs incurred in deploying advanced metering and meter information networks. Benefits of the advanced metering installation include improved safety, on-demand meter reading, enhanced outage identification and restoration and system monitoring of voltages. In 2007, the PUCT issued its advanced metering rule to implement this legislation. This rule outlined the minimum required functionality for an electric utility’s advanced metering systems to qualify for cost recovery under a surcharge. Subsequent to the issuance of the rule, the PUCT opened an implementation proceeding for market participants to fine-tune the rule requirements, address the impacts of advanced metering deployment on retail and wholesale markets in ERCOT, and help ensure that retail customers receive benefits from advanced metering deployment. The implementation proceeding is expected to continue through the end of 2010.
Advanced Metering Deployment Surcharge Filing— In May 2008, Oncor filed with the PUCT a description and request for approval of its proposed advanced metering system deployment plan and its proposed surcharge for the recovery of its estimated future investment for advanced metering deployment. Oncor’s plan provides for the full deployment of over three million advanced meters by the end of 2012 to all residential and most non-residential retail electricity customers in Oncor’s service area. As of December 31, 2009, Oncor has installed approximately 660 thousand advanced digital meters, including 620 thousand in the year ended December 31, 2009. Cumulative capital expenditures for the deployment of the advanced meter system totaled $196 million as of December 31, 2009, including $166 million in the year ended December 31, 2009.
In August 2008, a settlement was reached with the majority of the parties to this surcharge filing. The settlement included the following major provisions, as amended by the final order in the 2008 rate review:
| • | a surcharge beginning on January 1, 2009 and continuing for 11 years; |
| • | a total revenue requirement over the surcharge period of $1.023 billion; |
| • | estimated capital expenditures for advanced metering facilities of $686 million; |
| • | related operation and maintenance expenses for the surcharge period of $153 million; |
| • | $204 million of operation and maintenance expense savings, and |
| • | an advanced metering cost recovery factor of $2.19 per month per residential retail customer and varying from $2.39 to $5.15 per month for non-residential retail customers. |
An order approving the settlement was issued by the PUCT in August 2008 and became final in September 2008. Oncor began billing the advanced metering surcharge in the January 2009 billing month cycle. Oncor may, through subsequent reconciliation proceedings, request recovery of additional costs that are reasonable and necessary. While there is a presumption that costs spent in accordance with a plan approved by the PUCT are reasonable and necessary, recovery of any costs that are found not to have been spent or properly allocated, or not to be reasonable or necessary, must be refunded.
Transmission Rates — In order to recover increases in its transmission costs, including incremental fees paid to other transmission service providers due to an increase in their rates, Oncor is allowed to request an update twice a year to the transmission cost recovery factor (TCRF) component of its retail delivery rate charged to REPs. In January 2010, an application was filed to increase the TCRF, which is expected to be administratively approved and become effective in March 2010. This application is expected to increase annualized revenues by $13 million.
In September 2009, Oncor filed an application for an interim update of its wholesale transmission rate, and the PUCT approved the new rate effective December 2009. Accordingly, annualized revenues are expected to increase by approximately $34 million. Approximately $21 million of this increase is recoverable through transmission rates charged to wholesale customers, and the remaining $13 million is recoverable from REPs through the TCRF component of Oncor’s delivery rates.
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Application for 2010 Energy Efficiency Cost Recovery Factor — In May 2009, Oncor filed an application with the PUCT to request approval of an energy efficiency cost recovery factor (EECRF) for 2010. PUCT rules require Oncor to make an annual EECRF filing by May 1 for implementation at the beginning of the next calendar year. The requested 2010 EECRF is $54 million, the same amount established for 2009, and would result in the same $0.92 per month charge for residential customers as proposed in Oncor’s rate case. As allowed by the rule, the 2010 EECRF is designed to recover the costs of the 2010 programs, the under-recovery of 2008 program costs, and a performance bonus based on 2008 results. In its November 2009 order, the PUCT approved the application with minor modifications, resulting in an immediate recognition of $9 million in revenues, representing the performance bonus. The final order resulted in a residential EECRF of $0.89 per month due to the PUCT approval of a different allocation methodology for the performance bonus. Oncor’s new EECRF rider became effective for billings on and after December 30, 2009.
Competitive Renewable Energy Zones (CREZs) — In January 2009, the PUCT awarded approximately $1.3 billion of CREZ construction projects to Oncor. The projects involve the construction of transmission lines to support the transmission of electricity from renewable energy sources, principally wind generation facilities, in west Texas to population centers in the eastern part of the state. A written order reflecting the PUCT’s decision was entered in March 2009, and an order on rehearing was issued by the PUCT in May 2009. The cost estimates for the CREZ construction projects are based upon cost analyses prepared by ERCOT in April 2008. For the year ended December 31, 2009, Oncor’s CREZ-related capital expenditures totaled $114 million. It is expected that the necessary permitting actions and other requirements and all construction activities for Oncor’s CREZ construction projects will be completed by the end of 2013.
In October 2009, the PUCT initiated a proceeding to determine whether there is sufficient financial commitment from generators of renewable energy to grant Certificates of Convenience and Necessity (CCNs) for transmission facilities located in two areas in the panhandle of Texas designated as CREZs. If the PUCT determines that there is not sufficient financial commitment from the generators for either CREZ, the PUCT may take action, including delaying the filing of CREZ CCN applications until such time as the PUCT finds sufficient financial commitment for that CREZ in accordance with the financial commitment provisions of the PUCT’s rules. Three of the CREZ transmission projects awarded to Oncor are located in the two CREZs that are the subject of the proceeding. The estimated cost of these three transmission projects is approximately $380 million. The PUCT held a hearing in this proceeding in January 2010. Oncor expects the PUCT to issue an order concluding this proceeding in the second quarter of 2010.
In July 2009, the City of Garland, Texas filed an Original Petition and Application for Stay and Injunction in the 200th District Court of Travis County, Texas seeking judicial review and a stay of the PUCT’s March 2009 written order selecting transmission service providers (including Oncor) to build CREZ transmission facilities. In January 2010, the district court issued an order reversing the PUCT’s order and remanding it to the PUCT for action consistent with the court’s opinion. The district court order did not contain a stay or injunction and severed the City of Garland’s requests for declaratory and injunctive relief. On February 4, 2010, the PUCT issued an order that severs certain of the CREZ transmission projects awarded to Oncor and others from its consideration of the remand of the written order. On February 12, 2010, the PUCT issued an order suspending the schedule sequencing CREZ projects subsequent to CREZ priority projects. In the original sequencing order, Oncor was scheduled to file CCN applications for its five CREZ subsequent projects between March and May 2010. The PUCT’s order stated that the record evidence regarding the selection of the transmission service providers for the CREZ subsequent projects will be reevaluated without delay. Oncor cannot predict the impact, if any, the reevaluation may have on its CREZ construction projects.
Sunset Review
PURA, the PUCT and the RRC will be subject to “sunset” review by the Texas Legislature in the 2011 legislative session. Sunset review includes, generally, a comprehensive review of the need for and effectiveness of an administrative agency (the PUCT or the RRC), along with an evaluation of the advisability of any changes to the PUCT’s authorizing legislation (PURA). A Sunset staff report is scheduled to be issued in April 2010, and a Sunset public meeting is scheduled for May 2010. We cannot predict the outcome of the Sunset review process.
Summary
We cannot predict future regulatory or legislative actions or any changes in economic and securities market conditions. Such actions or changes could significantly alter our basic financial position, results of operations or cash flows.
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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 indebtedness, as well as exchange traded, over-the-counter contracts and other contractual arrangements to manage commodity price risk.
Risk Oversight
TCEH manages the commodity price, counterparty credit and commodity-related operational risk related to the unregulated energy business within limitations established by senior management and in accordance with overall risk management policies. Interest rate risk is managed centrally by the corporate treasury function. Market risks are monitored by risk management groups that operate independently of the wholesale commercial operations, utilizing defined practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and include, but are not limited to, Value at Risk (VaR) methodologies. Key risk control activities include, but are not limited to, transaction review and approval (including credit review), operational and market risk measurement, validation of transaction capture, portfolio valuation and reporting, including mark-to-market valuation, VaR and other risk measurement metrics.
We have a corporate risk management organization that is headed by the Chief Financial Officer, who also functions as the Chief Risk Officer. The Chief Risk Officer, through his designees, enforces applicable risk limits, including the respective policies and procedures to ensure compliance with such limits and evaluates the risks inherent in our businesses.
Commodity Price Risk
TCEH is subject to the inherent risks of market fluctuations in the price of electricity, natural gas and other energy-related products it markets or purchases. The company actively manages its portfolio of owned generation assets, fuel supply and retail sales load to mitigate the near-term impacts of these risks on results of operations. The company, similar to other participants in the market, cannot fully manage the long-term value impact of structural declines or increases in natural gas and power prices and spark spreads (differences between the market price of electricity and its cost of production).
In managing energy price risk, TCEH enters into a variety of market transactions including, but not limited to, short- and long-term contracts for physical delivery, exchange traded and over-the-counter financial contracts and bilateral contracts with customers. Activities include hedging, the structuring of long-term contractual arrangements and proprietary trading. The company continuously monitors the valuation of identified risks and adjusts positions based on current market conditions. The company strives to use consistent assumptions regarding forward market price curves in evaluating and recording the effects of commodity price risk.
Long-Term Hedging Program— See “Significant Activities and Events” above for a description of the program, including potential effects on reported results.
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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, 2009 | Year Ended December 31, 2008 | |||||
Month-end average Trading VaR: | $ | 4 | $ | 6 | ||
Month-end high Trading VaR: | $ | 7 | $ | 15 | ||
Month-end low Trading VaR: | $ | 2 | $ | 2 | ||
VaR for Energy-Related Contracts Subject to Mark-to-Market (MtM) Accounting — This measurement estimates the potential loss in fair value, due to changes in market conditions, of all contracts marked-to-market in net income (principally hedges not accounted for as cash flow hedges and trading positions), based on a 95% confidence level and an assumed holding period of five to 60 days.
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | |||||
Month-end average MtM VaR: | $ | 1,050 | $ | 2,290 | ||
Month-end high MtM VaR: | $ | 1,470 | $ | 3,549 | ||
Month-end low MtM VaR: | $ | 638 | $ | 1,087 | ||
Earnings at Risk (EaR)— This measurement estimates the potential reduction of pretax earnings for the periods presented, due to changes in market conditions, of all energy-related contracts marked-to-market in net income and contracts not marked-to-market in net income that are expected to be settled within the fiscal year (physical purchases and sales of commodities). Transactions accounted for as cash flow hedges are also included for this measurement. A 95% confidence level and a five to 60 day holding period are assumed in determining EaR.
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | |||||
Month-end average EaR: | $ | 1,088 | $ | 2,300 | ||
Month-end high EaR: | $ | 1,511 | $ | 3,916 | ||
Month-end low EaR: | $ | 676 | $ | 1,069 | ||
The decreases in the risk measures (MtM VaR and EaR) above were primarily driven by lower natural gas prices in 2009.
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Interest Rate Risk
The table below provides information concerning our financial instruments as of December 31, 2009 and 2008 that are sensitive to changes in interest rates, which include debt obligations and interest rate swaps. We have entered into interest rate swaps under which we have exchanged the difference between fixed-rate and variable-rate interest amounts calculated with reference to specified notional principal amounts at dates that generally coincide with interest payments under our credit facilities. In addition, in connection with entering into certain interest rate basis swaps to further reduce fixed borrowing costs, TCEH has changed the variable interest rate terms of certain debt from three-month LIBOR to one-month LIBOR, as discussed in Note 12 to 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 12 to Financial Statements for a discussion of changes in debt obligations.
| Expected Maturity Date | Successor | |||||||||||||||||||||||||||||||||||||
| (millions of dollars, except percentages) | ||||||||||||||||||||||||||||||||||||||
| 2010 | 2011 | 2012 | 2013 | 2014 | There- After | 2009 Total Carrying Amount | 2009 Total Fair Value | 2008 Total Carrying Amount | 2008 Total Fair Value | |||||||||||||||||||||||||||||
Long-term debt (including current maturities): | ||||||||||||||||||||||||||||||||||||||
Fixed rate debt amount (a) | $ | 135 | $ | 559 | $ | 851 | $ | 866 | $ | 1,163 | $ | 17,287 | $ | 20,861 | $ | 17,296 | $ | 20,646 | $ | 14,266 | ||||||||||||||||||
Average interest rate | 5.46 | % | 5.66 | % | 6.24 | % | 6.00 | % | 5.57 | % | 9.59 | % | 8.95 | % | 8.70 | % | ||||||||||||||||||||||
Variable rate debt amount | $ | 205 | $ | 205 | $ | 205 | $ | 205 | $ | 20,583 | $ | 205 | $ | 21,608 | $ | 17,463 | $ | 21,261 | $ | 14,886 | ||||||||||||||||||
Average interest rate | 3.74 | % | 3.74 | % | 3.74 | % | 3.74 | % | 3.74 | % | 0.29 | % | 3.71 | % | 5.28 | % | ||||||||||||||||||||||
Total debt | $ | 340 | $ | 764 | $ | 1,056 | $ | 1,071 | $ | 21,746 | $ | 17,492 | $ | 42,469 | $ | 34,759 | $ | 41,907 | $ | 29,152 | ||||||||||||||||||
Debt swapped to fixed: | ||||||||||||||||||||||||||||||||||||||
Amount | $ | 500 | $ | 600 | $ | 2,600 | $ | 3,600 | $ | 9,000 | $ | — | $ | 16,300 | $ | 17,550 | ||||||||||||||||||||||
Average pay rate | 7.43 | % | 7.57 | % | 7.99 | % | 7.60 | % | 8.18 | % | — | 7.98 | % | 8.00 | % | |||||||||||||||||||||||
Average receive rate | 3.74 | % | 3.74 | % | 3.74 | % | 3.74 | % | 3.74 | % | — | 3.74 | % | 5.88 | % | |||||||||||||||||||||||
Variable basis swaps: | ||||||||||||||||||||||||||||||||||||||
Amount | $ | 3,600 | $ | 5,450 | $ | 7,200 | $ | — | $ | — | $ | — | $ | 16,250 | $ | 13,045 | ||||||||||||||||||||||
Average pay rate | 0.32 | % | 0.33 | % | 0.33 | % | — | — | — | 0.33 | % | 2.48 | % | |||||||||||||||||||||||||
Average receive rate | 0.24 | % | 0.24 | % | 0.24 | % | — | — | — | 0.24 | % | 2.00 | % | |||||||||||||||||||||||||
| (a) | Reflects the remarketing date and not the maturity date for certain debt that is subject to mandatory tender for remarketing prior to maturity. See Note 12 to Financial Statements for details concerning long-term debt subject to mandatory tender for remarketing. |
As of December 31, 2009, the potential reduction of annual pretax earnings due to a one percentage point (100 basis points) increase in floating interest rates on long-term debt totaled approximately $42 million, taking into account the interest rate swaps discussed in Note 12 to 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 arising from hedging and trading activities totaled $2.616 billion at December 31, 2009. The components of this exposure are discussed in more detail below.
Assets subject to credit risk as of December 31, 2009 include $897 million in accounts receivable from the retail sale of electricity to residential and business customers. Cash deposits held as collateral for these receivables totaled $83 million at December 31, 2009. The risk of material loss (after consideration of bad debt allowances) from nonperformance by these customers is unlikely based upon historical experience. Allowances for uncollectible accounts receivable are established for the potential loss from nonpayment by these customers based on historical experience, market or operational conditions and changes in the financial condition of large business customers.
Assets subject to credit risk also include accounts receivable from electricity transmission and distribution services. This exposure, which totaled $245 million at December 31, 2009, consists almost entirely of noninvestment grade trade accounts receivable. Of this amount, $180 million represents trade accounts receivable from REPs. Oncor has a customer with subsidiaries that collectively represent 11% of the total exposure. No other nonaffiliated parties represent 10% or more of the total exposure.
The remaining credit exposure arises from wholesale energy sales and purchases and hedging and trading activities, including interest rate hedging. Counterparties to these transactions include energy companies, financial institutions, electric utilities, independent power producers, oil and gas producers, local distribution companies and energy trading and marketing companies. As of December 31, 2009, the exposure to credit risk from these counterparties totaled $1.474 billion taking into account the standardized master netting contracts and agreements described above but before taking into account $177 million in credit collateral (cash, letters of credit and other credit support). The net exposure (after credit collateral) of $1.297 billion increased approximately $502 million in the year ended December 31, 2009, driven by increased derivative asset/decreased derivative liability values due to the effect of changes in natural gas prices and interest rates on the values of our hedge positions.
Of this $1.297 billion net exposure, 99.7% is with investment grade customers and counterparties, as determined using publicly available information including major rating agencies’ published ratings and our internal credit evaluation process. Those customers and counterparties without a S&P rating of at least BBB- or similar rating from another major rating agency are rated using internal credit methodologies and credit scoring models to estimate a S&P equivalent rating. The company routinely monitors and manages credit exposure to these customers and counterparties on this basis.
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The following table presents the distribution of credit exposure as of December 31, 2009 arising from wholesale energy sales and purchases and hedging and trading activities. This credit exposure represents wholesale trade accounts receivable and net asset positions on the balance sheet arising from hedging and trading activities after taking into consideration netting and setoff provisions within each contract and any master netting contracts with counterparties.
| Net 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 | $ | 1,467 | $ | 174 | $ | 1,293 | $ | 880 | $ | 413 | $ | — | $ | 1,293 | |||||||||
Noninvestment grade | 7 | 3 | 4 | 4 | — | — | 4 | ||||||||||||||||
Totals | $ | 1,474 | $ | 177 | $ | 1,297 | $ | 884 | $ | 413 | $ | — | $ | 1,297 | |||||||||
Investment grade | 99.5 | % | 99.7 | % | |||||||||||||||||||
Noninvestment grade | 0.5 | % | 0.3 | % | |||||||||||||||||||
In addition to the exposures in the table above, contracts classified as “normal” purchase or sale and non-derivative contractual commitments are not marked-to-market in the financial statements. Such contractual commitments may contain pricing that is favorable considering current market conditions and therefore represent economic risk if the counterparties do not perform. Nonperformance could have a material adverse impact on future results of operations, financial condition and cash flows.
Significant (10% or greater) concentration of credit exposure exists with three counterparties, which represented 41%, 37% and 12% of the net $1.297 billion exposure. We view exposure to these counterparties to be within an acceptable level of risk tolerance due to the applicable counterparty’s credit rating and the importance of our business relationship with the counterparty. However, this concentration increases the risk that a default would have a material effect on results of operations.
With respect to credit risk related to the long-term hedging program, over 99% of the transaction volumes are with counterparties with an A credit rating or better. However, there is current and potential credit concentration risk related to the limited number of counterparties that comprise the substantial majority of the program with such counterparties being in the banking and financial sector. The transactions with these counterparties contain certain credit rating provisions that would require the counterparties to post collateral in the event of a material downgrade in the credit rating of the counterparties. An event of default by one or more hedge counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts of expected settlements if the hedge counterparties owe amounts to us. While the potential concentration of risk with these counterparties is viewed to be within an acceptable risk tolerance, the exposure to hedge counterparties is managed through the various ongoing risk management measures described above.
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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 business and operations (often, but not always, through the use of words or phrases such as “will likely result,” “are expected to,” “will continue,” “is anticipated,” “estimated,” “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 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, FERC, the PUCT, the RRC, the NRC, the EPA and the TCEQ, 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 mines; |
| • | acquisitions and disposal of assets and facilities; |
| • | development, construction and operation of facilities; |
| • | decommissioning costs; |
| • | present or prospective wholesale and retail competition; |
| • | changes in tax laws and policies, and |
| • | changes in and compliance with environmental and safety laws and policies, including climate change initiatives; |
| • | legal and administrative proceedings and settlements; |
| • | general industry trends; |
| • | economic conditions, including the current recessionary environment; |
| • | our ability to attract and retain profitable customers; |
| • | our ability to profitably serve our customers; |
| • | restrictions on competitive retail pricing; |
| • | changes in wholesale electricity prices or energy commodity prices; |
| • | changes in prices of transportation of natural gas, coal, crude oil and refined products; |
| • | unanticipated changes in market heat rates in the ERCOT electricity market; |
| • | our ability to effectively hedge against changes in commodity prices, market heat rates and interest rates; |
| • | weather conditions and other natural phenomena, and acts of sabotage, wars or terrorist activities; |
| • | unanticipated population growth or decline, or changes in market demand and demographic patterns; |
| • | 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 credit markets; |
| • | access to capital, the cost of such capital, and the results of financing and refinancing efforts, including availability of funds in capital markets; |
| • | financial restrictions placed on us by our credit facilities and indentures governing our debt instruments; |
| • | our ability to generate sufficient cash flow to make interest payments on our debt instruments; |
| • | competition for new energy development and other business opportunities; |
| • | inability of various counterparties to meet their obligations with respect to our financial instruments; |
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| • | changes in technology used by and services offered by us; |
| • | changes in electricity transmission that allow additional electricity generation to compete with our generation assets; |
| • | significant changes in our relationship with our employees, including the availability of qualified personnel, and the potential adverse effects if labor disputes or grievances were to occur; |
| • | changes in assumptions used to estimate costs of providing employee benefits, including pension and OPEB benefits, 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; |
| • | our ability to implement cost reduction initiatives, and |
| • | with respect to our lignite-fueled generation construction and development program, more specifically, our ability to fund such investments, changes in competitive market rules, adverse judicial rulings, changes in environmental laws or regulations, changes in electric generation and emissions control technologies, changes in projected demand for electricity, changes in wholesale electricity prices or energy commodity prices, transmission capacity and constraints, force majeure events and our ability to manage the significant construction, commissioning and start-up program to a timely conclusion with limited cost overruns. |
Any forward-looking statement speaks only as of the date on which it is made, and there is no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
INDUSTRY AND MARKET INFORMATION
The industry and market data and other statistical information used throughout this 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 or the PUCT. 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, 2009 and 2008 (successor), and the related statements of consolidated income (loss), comprehensive income (loss), cash flows and equity for the years ended December 31, 2009 and 2008 (successor), the period from October 11, 2007 through December 31, 2007 (successor) and the period from January 1, 2007 through October 10, 2007 (predecessor). These financial statements are the responsibility of EFH Corp.’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Energy Future Holdings Corp. and subsidiaries as of December 31, 2009 and 2008 (successor), and the results of their operations and their cash flows for the years ended December 31, 2009 and 2008 (successor), the period from October 11, 2007 through December 31, 2007 (successor) and the period from January 1, 2007 through October 10, 2007 (predecessor), in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, EFH Corp. completed its merger with Texas Energy Future Merger Sub Corp and became a subsidiary of Texas Energy Future Holdings Limited Partnership on October 10, 2007.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), EFH Corp.’s internal control over financial reporting as of December 31, 2009, based on the criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 18, 2010 expressed an unqualified opinion on EFH Corp.’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 18, 2010
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME (LOSS)
(Millions of Dollars)
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||
Operating revenues | $ | 9,546 | $ | 11,364 | $ | 1,994 | $ | 8,044 | ||||||||
Fuel, purchased power costs and delivery fees | (2,878 | ) | (4,595 | ) | (644 | ) | (2,381 | ) | ||||||||
Net gain (loss) from commodity hedging and trading activities | 1,736 | 2,184 | (1,492 | ) | (554 | ) | ||||||||||
Operating costs | (1,598 | ) | (1,503 | ) | (306 | ) | (1,107 | ) | ||||||||
Depreciation and amortization | (1,754 | ) | (1,610 | ) | (415 | ) | (634 | ) | ||||||||
Selling, general and administrative expenses | (1,068 | ) | (957 | ) | (216 | ) | (691 | ) | ||||||||
Franchise and revenue-based taxes | (359 | ) | (363 | ) | (93 | ) | (282 | ) | ||||||||
Impairment of goodwill (Note 3) | (90 | ) | (8,860 | ) | — | — | ||||||||||
Other income (Note 10) | 204 | 80 | 14 | 69 | ||||||||||||
Other deductions (Note 10) | (97 | ) | (1,301 | ) | (61 | ) | (841 | ) | ||||||||
Interest income | 45 | 27 | 24 | 56 | ||||||||||||
Interest expense and related charges (Note 25) | (2,912 | ) | (4,935 | ) | (839 | ) | (671 | ) | ||||||||
Income (loss) from continuing operations before income taxes | 775 | (10,469 | ) | (2,034 | ) | 1,008 | ||||||||||
Income tax (expense) benefit | (367 | ) | 471 | 673 | (309 | ) | ||||||||||
Income (loss) from continuing operations | 408 | (9,998 | ) | (1,361 | ) | 699 | ||||||||||
Income from discontinued operations, net of tax effect (Note 1) | — | — | 1 | 24 | ||||||||||||
Net income (loss) | 408 | (9,998 | ) | (1,360 | ) | 723 | ||||||||||
Net (income) loss attributable to noncontrolling interests | (64 | ) | 160 | — | — | |||||||||||
Net income (loss) attributable to EFH Corp. | $ | 344 | $ | (9,838 | ) | $ | (1,360 | ) | $ | 723 | ||||||
See Notes to Financial Statements.
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
(Millions of Dollars)
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||
Net income (loss) | $ | 408 | $ | (9,998 | ) | $ | (1,360 | ) | $ | 723 | ||||||
Other comprehensive income (loss), net of tax effects: | ||||||||||||||||
Reclassification of pension and other retirement benefit costs (net of tax (expense) benefit of $20, $69, $5, and $(19)) (Note 21) | (40 | ) | (84 | ) | (57 | ) | 49 | |||||||||
Cash flow hedges: | ||||||||||||||||
Net decrease in fair value of derivatives (net of tax benefit of $10, $99, $97 and $154) | (20 | ) | (183 | ) | (177 | ) | (288 | ) | ||||||||
Derivative value net (gains) losses related to hedged transactions recognized during the period and reported in net income (net of tax (expense) benefit of $72, $66, $— and $(48)) | 130 | 122 | — | (89 | ) | |||||||||||
Total effect of cash flow hedges | 110 | (61 | ) | (177 | ) | (377 | ) | |||||||||
Total adjustments to net income (loss) | 70 | (145 | ) | (234 | ) | (328 | ) | |||||||||
Comprehensive income (loss) | 478 | (10,143 | ) | (1,594 | ) | 395 | ||||||||||
Comprehensive (income) loss attributable to noncontrolling interests | (64 | ) | 160 | — | — | |||||||||||
Comprehensive income (loss) attributable to EFH Corp. | $ | 414 | $ | (9,983 | ) | $ | (1,594 | ) | $ | 395 | ||||||
See Notes to Financial Statements.
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||
Cash flows — operating activities | ||||||||||||||||
Net income (loss) | $ | 408 | $ | (9,998 | ) | $ | (1,360 | ) | $ | 723 | ||||||
Income from discontinued operations, net of tax effect | — | — | (1 | ) | (24 | ) | ||||||||||
Income (loss) from continuing operations | 408 | (9,998 | ) | (1,361 | ) | 699 | ||||||||||
Adjustments to reconcile income from continuing operations to cash provided by operating activities: | ||||||||||||||||
Depreciation and amortization | 2,172 | 2,070 | 568 | 684 | ||||||||||||
Deferred income tax expense (benefit) – net | 253 | (477 | ) | (736 | ) | (111 | ) | |||||||||
Impairment of goodwill (Note 3) | 90 | 8,860 | — | — | ||||||||||||
Impairment of trade name intangible asset (Note 3) | — | 481 | — | — | ||||||||||||
Impairment of emission allowances intangible assets (Note 3) | — | 501 | — | — | ||||||||||||
Impairment of natural gas-fueled generation facilities (Note 5) | — | 229 | — | — | ||||||||||||
Impairment of land (Note 10) | 34 | — | — | — | ||||||||||||
Charge related to Lehman bankruptcy (Note 10) | — | 26 | — | — | ||||||||||||
Write off of regulatory assets (Note 25) | 25 | — | — | — | ||||||||||||
Increase of toggle notes in lieu of cash interest (Note 12) | 511 | — | — | — | ||||||||||||
Unrealized net (gains) losses from mark-to-market valuations of commodity positions | (1,225 | ) | (2,329 | ) | 1,556 | 722 | ||||||||||
Unrealized net (gains) losses from mark-to-market valuations of interest rate swaps | (696 | ) | 1,477 | — | — | |||||||||||
Net gain on debt exchanges (Note 12) | (87 | ) | — | — | — | |||||||||||
Bad debt expense (Note 11) | 113 | 81 | 12 | 46 | ||||||||||||
Stock-based incentive compensation expense | 14 | 30 | — | 27 | ||||||||||||
Reversal of reserves recorded in purchase accounting (Note 10) | (44 | ) | — | — | — | |||||||||||
Losses on dedesignated cash flow hedges (interest rate swaps) | 184 | 66 | — | 10 | ||||||||||||
Net charges related to cancelled development of generation facilities (Note 4) | — | — | 2 | 676 | ||||||||||||
Write-off of deferred transaction costs (Note 10) | — | — | — | 38 | ||||||||||||
Credit related to impaired leases (Note 10) | — | — | — | (48 | ) | |||||||||||
Net gains on sale of assets, including amortization of deferred gains | (5 | ) | (1 | ) | (1 | ) | (40 | ) | ||||||||
Other, net | (4 | ) | (20 | ) | 5 | 19 | ||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||
Accounts receivable – trade | (125 | ) | (505 | ) | 309 | (200 | ) | |||||||||
Impact of accounts receivable sales program (Note 11) | (33 | ) | 53 | (336 | ) | 72 | ||||||||||
Inventories | (59 | ) | (21 | ) | (5 | ) | (7 | ) | ||||||||
Accounts payable – trade | (141 | ) | 385 | (264 | ) | 81 | ||||||||||
Commodity and other derivative contractual assets and liabilities | (64 | ) | (28 | ) | 18 | (185 | ) | |||||||||
Margin deposits – net | 248 | 595 | (614 | ) | (569 | ) | ||||||||||
Deferred advanced metering system revenues (Note 25) | 57 | — | — | — | ||||||||||||
Other – net assets | (43 | ) | 440 | 284 | (89 | ) | ||||||||||
Other – net liabilities | 128 | (410 | ) | 113 | 440 | |||||||||||
Cash provided by (used in) operating activities from continuing operations | $ | 1,711 | $ | 1,505 | $ | (450 | ) | $ | 2,265 | |||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS (CONT.)
(Millions of Dollars)
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||
Cash flows — financing activities | ||||||||||||||||
Issuances of long-term debt/securities (Note 12): | ||||||||||||||||
Equity financing from Sponsor Group and other investors | $ | — | $ | — | $ | 8,236 | $ | — | ||||||||
Merger-related debt financing | — | — | 42,732 | 1,800 | ||||||||||||
Pollution control revenue bonds | — | 242 | — | — | ||||||||||||
Oncor long-term debt | — | 1,500 | — | — | ||||||||||||
Other long-term debt | 522 | 1,443 | — | — | ||||||||||||
Common stock | — | 34 | — | 1 | ||||||||||||
Repayments/repurchases of long-term debt/securities (Note 12): | ||||||||||||||||
Pollution control revenue bonds | — | (242 | ) | — | (143 | ) | ||||||||||
Merger-related debt repurchases | — | — | (15,314 | ) | — | |||||||||||
Other long-term debt | (396 | ) | (925 | ) | (81 | ) | (302 | ) | ||||||||
Common stock | — | (3 | ) | — | (13 | ) | ||||||||||
Increase (decrease) in short-term borrowings (Note 12): | ||||||||||||||||
Banks | 332 | (481 | ) | (722 | ) | 2,245 | ||||||||||
Commercial paper | — | — | — | (1,296 | ) | |||||||||||
Proceeds from sale of noncontrolling interests, net of transaction costs (Note 15) | — | 1,253 | — | — | ||||||||||||
Contributions from noncontrolling interests | 48 | — | — | — | ||||||||||||
Distributions paid to noncontrolling interests | (56 | ) | (2 | ) | — | — | ||||||||||
Common stock dividends paid | — | — | — | (788 | ) | |||||||||||
Settlements of minimum withholding tax liabilities under stock-based compensation plans | — | — | — | (93 | ) | |||||||||||
Debt discount, financing and reacquisition expenses | (49 | ) | (21 | ) | (986 | ) | (17 | ) | ||||||||
Other, net | 21 | 39 | — | — | ||||||||||||
Cash provided by financing activities from continuing operations | $ | 422 | $ | 2,837 | $ | 33,865 | $ | 1,394 | ||||||||
Cash flows — investing activities | ||||||||||||||||
Acquisition of EFH Corp. | — | — | (32,694 | ) | — | |||||||||||
Capital expenditures | (2,348 | ) | (2,849 | ) | (693 | ) | (2,366 | ) | ||||||||
Nuclear fuel purchases | (197 | ) | (166 | ) | (23 | ) | (54 | ) | ||||||||
Money market fund redemptions (investments) (Note 1) | 142 | (142 | ) | — | — | |||||||||||
Investment posted with derivative counterparty (Note 18) | (400 | ) | — | — | — | |||||||||||
Reduction of (proceeds from) letter of credit facility deposited with trustee (restricted cash) (Note 12) | 115 | — | (1,250 | ) | — | |||||||||||
Reduction of restricted cash related to pollution control revenue bonds | — | 29 | 13 | 202 | ||||||||||||
Other changes in restricted cash | 9 | 1 | 14 | (16 | ) | |||||||||||
Purchase of mining-related assets | — | — | — | (122 | ) | |||||||||||
Proceeds from sale of assets | 2 | 80 | 86 | 71 | ||||||||||||
Proceeds from sale of controlling interest in natural gas gathering pipeline business | 40 | — | — | — | ||||||||||||
Proceeds from sale of environmental allowances and credits | 19 | 39 | — | — | ||||||||||||
Purchases of environmental allowances and credits | (19 | ) | (34 | ) | — | — | ||||||||||
Cash settlements related to outsourcing contract termination (Note 20) | — | 70 | — | — | ||||||||||||
Settlement of loan (Note 20) | — | 25 | — | — | ||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | 3,064 | 1,623 | 831 | 602 | ||||||||||||
Investments in nuclear decommissioning trust fund securities | (3,080 | ) | (1,639 | ) | (835 | ) | (614 | ) | ||||||||
Other, net | 20 | 29 | (12 | ) | 14 | |||||||||||
Cash used in investing activities from continuing operations | $ | (2,633 | ) | $ | (2,934 | ) | $ | (34,563 | ) | $ | (2,283 | ) | ||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS (CONT.)
(Millions of Dollars)
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||
Discontinued operations: | ||||||||||||||
Cash provided by (used in) operating activities | — | — | (7 | ) | 35 | |||||||||
Cash used in financing activities | — | — | — | — | ||||||||||
Cash provided by (used in) investing activities | — | — | — | — | ||||||||||
Cash provided by (used in) discontinued operations | — | — | (7 | ) | 35 | |||||||||
Net change in cash and cash equivalents | (500 | ) | 1,408 | (1,155 | ) | 1,411 | ||||||||
Cash and cash equivalents — beginning balance | 1,689 | 281 | 1,436 | 25 | ||||||||||
Cash and cash equivalents — ending balance | $ | 1,189 | $ | 1,689 | $ | 281 | $ | 1,436 | ||||||
See Notes to Financial Statements.
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
| Successor | ||||||||
| December 31, 2009 | December 31, 2008 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents (Note 1) | $ | 1,189 | $ | 1,689 | ||||
Investment posted with counterparty (Note 18) | 425 | — | ||||||
Investments held in money market fund (Note 1) | — | 142 | ||||||
Restricted cash (Note 25) | 48 | 55 | ||||||
Trade accounts receivable — net (Note 11) | 1,260 | 1,219 | ||||||
Income taxes receivable — net | — | 42 | ||||||
Inventories (Note 25) | 485 | 426 | ||||||
Commodity and other derivative contractual assets (Note 18) | 2,391 | 2,534 | ||||||
Accumulated deferred income taxes (Note 9) | 5 | 44 | ||||||
Margin deposits related to commodity positions | 187 | 439 | ||||||
Other current assets | 136 | 165 | ||||||
Total current assets | 6,126 | 6,755 | ||||||
Restricted cash (Note 25) | 1,149 | 1,267 | ||||||
Investments (Note 19) | 750 | 645 | ||||||
Property, plant and equipment — net (Note 25) | 30,108 | 29,522 | ||||||
Goodwill (Note 3) | 14,316 | 14,386 | ||||||
Intangible assets — net (Note 3) | 2,876 | 2,993 | ||||||
Regulatory assets — net (Note 25) | 1,959 | 1,892 | ||||||
Commodity and other derivative contractual assets (Note 18) | 1,533 | 962 | ||||||
Other noncurrent assets, principally unamortized debt issuance costs | 845 | 841 | ||||||
Total assets | $ | 59,662 | $ | 59,263 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Short-term borrowings (Note 12) | $ | 1,569 | $ | 1,237 | ||||
Long-term debt due currently (Note 12) | 417 | 385 | ||||||
Trade accounts payable | 896 | 1,143 | ||||||
Commodity and other derivative contractual liabilities (Note 18) | 2,392 | 2,908 | ||||||
Margin deposits related to commodity positions | 520 | 525 | ||||||
Accrued interest | 526 | 524 | ||||||
Other current liabilities | 744 | 612 | ||||||
Total current liabilities | 7,064 | 7,334 | ||||||
Accumulated deferred income taxes (Note 9) | 6,131 | 6,067 | ||||||
Investment tax credits | 37 | 42 | ||||||
Commodity and other derivative contractual liabilities (Note 18) | 1,060 | 2,095 | ||||||
Long-term debt, less amounts due currently (Note 12) | 41,440 | 40,838 | ||||||
Other noncurrent liabilities and deferred credits (Note 25) | 5,766 | 5,205 | ||||||
Total liabilities | 61,498 | 61,581 | ||||||
Commitments and Contingencies (Note 13) | ||||||||
Equity (Note 14): | ||||||||
EFH Corp. shareholders’ equity | (3,247 | ) | (3,673 | ) | ||||
Noncontrolling interests in subsidiaries | 1,411 | 1,355 | ||||||
Total equity | (1,836 | ) | (2,318 | ) | ||||
Total liabilities and equity | $ | 59,662 | $ | 59,263 | ||||
See Notes to Financial Statements.
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED EQUITY
(Millions of Dollars)
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||
Common stock stated value of $0.001 effective May 2009 (number of authorized shares — Successor — 2,000,000,000; Predecessor — 1,000,000,000): | ||||||||||||||||
Balance at beginning of period | $ | — | $ | — | $ | — | $ | 5 | ||||||||
Effects of shareholder actions related to stated value of common stock | 2 | — | — | — | ||||||||||||
Balance at end of period (number of shares outstanding: Successor: 2009 — 1,668,065,133; 2008 — 1,667,149,663; 2007 — 1,664,345,953; Predecessor: October 10, 2007 — 461,152,009 | 2 | — | — | 5 | ||||||||||||
Additional paid-in capital: | ||||||||||||||||
Balance at beginning of period | 7,904 | 8,279 | — | 1,104 | ||||||||||||
Investment by Sponsor Group and other investors | — | — | 8,279 | — | ||||||||||||
Effects of stock-based incentive compensation plans | 11 | 29 | — | (66 | ) | |||||||||||
Effects of shareholder actions related to stated value of common stock | (2 | ) | — | — | — | |||||||||||
Effect of sale of noncontrolling interests (Note 15) | — | (406 | ) | — | — | |||||||||||
Common stock repurchases | — | — | — | (13 | ) | |||||||||||
Excess tax benefit on stock-based compensation | — | — | — | 82 | ||||||||||||
Cost of Thrift Plan shares released by LESOP trustee (Note 21) | — | — | — | 210 | ||||||||||||
Effects of executive deferred compensation plan | — | — | — | 11 | ||||||||||||
Other | 1 | 2 | — | (2 | ) | |||||||||||
Balance at end of period | 7,914 | 7,904 | 8,279 | 1,326 | ||||||||||||
Retained earnings (deficit): | ||||||||||||||||
Balance at beginning of period | (11,198 | ) | (1,360 | ) | — | 622 | ||||||||||
Net income (loss) attributable to EFH Corp. | 344 | (9,838 | ) | (1,360 | ) | 723 | ||||||||||
Dividends declared on common stock ($—,$—, $—, and $1.30 per share) | — | — | — | (596 | ) | |||||||||||
Effect of adoption of accounting guidance related to uncertain tax positions (Note 8) | — | — | — | 33 | ||||||||||||
LESOP dividend deduction tax benefit and other | — | — | — | 3 | ||||||||||||
Balance at end of period | (10,854 | ) | (11,198 | ) | (1,360 | ) | 785 | |||||||||
Accumulated other comprehensive gain (loss), net of tax effects: | ||||||||||||||||
Pension and other postretirement employee benefit liability adjustments: | ||||||||||||||||
Balance at beginning of period | (141 | ) | (57 | ) | — | (2 | ) | |||||||||
Change in unrecognized gains (losses) related to pension and other retirement benefit costs | (40 | ) | (84 | ) | (57 | ) | 49 | |||||||||
Balance at end of period | (181 | ) | (141 | ) | (57 | ) | 47 | |||||||||
Amounts related to cash flow hedges: | ||||||||||||||||
Balance at beginning of period | (238 | ) | (177 | ) | — | 411 | ||||||||||
Change during the period | 110 | (61 | ) | (177 | ) | (377 | ) | |||||||||
Balance at end of period | (128 | ) | (238 | ) | (177 | ) | 34 | |||||||||
Total accumulated other comprehensive gain (loss) at end of period | (309 | ) | (379 | ) | (234 | ) | 81 | |||||||||
EFH Corp. shareholders’ equity at end of period (Note 14) | (3,247 | ) | (3,673 | ) | 6,685 | 2,197 | ||||||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED EQUITY (CONT.)
(Millions of Dollars)
| Successor | Predecessor | ||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | ||||||||||||
Noncontrolling interests in subsidiaries (Note 15): | |||||||||||||||
Balance at beginning of period | 1,355 | — | — | — | |||||||||||
Net income (loss) attributable to noncontrolling interests | 64 | (160 | ) | — | — | ||||||||||
Investment | 48 | 1,253 | — | — | |||||||||||
Effect of sale of noncontrolling interests | — | 265 | — | — | |||||||||||
Distributions to noncontrolling interests | (56 | ) | (2 | ) | — | — | |||||||||
Other | — | (1 | ) | — | — | ||||||||||
Noncontrolling interests in subsidiaries at end of period | 1,411 | 1,355 | — | — | |||||||||||
Total equity at end of period | $ | (1,836 | ) | $ | (2,318 | ) | $ | 6,685 | $ | 2,197 | |||||
See Notes to Financial Statements.
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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 conducting its operations principally through its TCEH and Oncor subsidiaries. TCEH is a holding company for subsidiaries engaged in competitive electricity market activities largely in Texas, including electricity generation, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales. Oncor is a majority (approximately 80%) owned subsidiary engaged in regulated electricity transmission and distribution operations in Texas.
On October 10, 2007, EFH Corp. completed its Merger with Merger Sub. As a result of the Merger, EFH Corp. became a subsidiary of Texas Holdings, which is controlled by the Sponsor Group. See Note 2.
References in 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 other obligations of any member of the Texas Holdings Group. Moreover, Oncor’s operations are conducted, and its cash flows managed, independently from the Texas Holdings Group. Oncor Holdings is consolidated with EFH Corp. as a variable interest entity under consolidations accounting standards.
See Note 15 for discussion of noncontrolling interests sold by Oncor in November 2008.
We have two reportable segments: the Competitive Electric segment, which is comprised principally of TCEH, and the Regulated Delivery segment, which is comprised of Oncor and its wholly-owned bankruptcy-remote financing subsidiary. See Note 24 for further information concerning reportable business segments.
Basis of Presentation
The consolidated financial statements have been prepared in accordance with US GAAP. The accompanying consolidated statements of income (loss), comprehensive income (loss), cash flows and equity present results of operations and cash flows for “Successor” and “Predecessor” periods, which relate to periods succeeding and preceding the Merger, respectively. The consolidated financial statements have been prepared on the same basis as the audited financial statements included in the 2008 Form 10-K. The consolidated financial statements of the Successor reflect the application of purchase accounting in accordance with the provisions of accounting standards related to business combinations, include the activities of Merger Sub, all of which related to the acquisition of EFH Corp., and reflect the adoption of accounting standards related to the determination of fair value. Certain reclassifications have been made to conform prior period data to current period presentation. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated. Subsequent events have been evaluated through February 18, 2010, the date these consolidated financial statements were issued.
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Discontinued Businesses
Results from discontinued businesses, which are reported as discontinued operations, during the period October 11, 2007 to December 31, 2007 totaled $1 million in net income and during the period from January 1, 2007 to October 10, 2007 totaled $24 million in net income and consisted primarily of insurance proceeds related to a 2005 TXU Europe litigation settlement agreement.
Use of Estimates
Preparation of financial statements requires estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments, other than those disclosed elsewhere herein, were made to previous estimates or assumptions during the current year.
Purchase Accounting
The Merger was accounted for under purchase accounting, whereby the total purchase price of the transaction was allocated to our identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values, and the excess of the purchase price over the fair value of net assets acquired was recorded as goodwill. The allocation resulted in a significant amount of goodwill, an increase in the carrying value of property, plant and equipment and deferred income tax liabilities as well as new identifiable intangible assets and liabilities. Reported earnings in periods subsequent to the Merger reflect increases in interest, depreciation and amortization expense. See Note 2 for details regarding the effect of purchase accounting.
Derivative Instruments and Mark-to-Market Accounting
We enter into contracts for the purchase and sale of electricity, natural gas and other commodities and also enter into other derivative instruments such as options, swaps, futures and forwards primarily to manage commodity price and interest rate risks. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, changes in the fair value of the derivative are recognized in net income as unrealized gains and losses, unless the criteria for certain exceptions are met, and an offsetting derivative asset or liability is recorded in the balance sheet. This recognition is referred to as “mark-to-market” accounting. The fair values of our unsettled derivative instruments under mark-to-market accounting are reported in the balance sheet as commodity and other derivative contractual assets or liabilities. When derivative instruments are settled and realized gains and losses are recorded, the previously recorded unrealized gains and losses and derivative assets and liabilities are reversed. See Notes 16 and 18 for additional information regarding fair value measurement and commodity and other derivative contractual assets and liabilities. Under the election criteria of accounting standards related to derivative instruments and hedging activities, we may elect the “normal” purchase and sale exemption. A commodity-related derivative contract may be designated as a “normal” purchase or sale if the commodity is to be physically received or delivered for use or sale in the normal course of business. If designated as normal, the derivative contract is accounted for under the accrual method of accounting (not marked-to-market) with no balance sheet or income statement recognition of the contract until settlement.
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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., a forecasted sale of electricity in the future at market prices or the payment of interest related to variable rate debt), while a fair value hedge mitigates risk associated with fixed future cash flows (e.g., debt with fixed interest rate payments). In accounting for changes in the fair value of cash flow hedges, derivative assets and liabilities are recorded on the balance sheet with an offset to other comprehensive income or loss to the extent the hedges are effective and the hedged transaction remains probable of occurring. If the hedged transaction becomes probable of not occurring, hedge accounting is discontinued and the amount recorded in other comprehensive income is immediately reclassified into net income. If the relationship between the hedge and the hedged transaction ceases to exist or is dedesignated, hedge accounting is discontinued, and the amounts recorded in other comprehensive income are recognized as the previously hedged transaction impacts earnings. Changes in value of fair value hedges are recorded as derivative assets or liabilities with an offset to net income, and the carrying value of the related asset or liability (hedged item) is adjusted for changes in fair value with an offset to net income. If the fair value hedge is settled prior to the maturity of the hedged item, the cumulative fair value gain or loss associated with the hedge is amortized into income over the remaining life of the hedged item. In the statement of cash flow, the effects of settlements of derivative instruments are classified consistent with the related hedged transactions.
To qualify for hedge accounting, a hedge must be considered highly effective in offsetting changes in fair value of the hedged item. Assessment of the hedge’s effectiveness is tested at least quarterly throughout its term to continue to qualify for hedge accounting. Changes in fair value that represent hedge ineffectiveness, even if the hedge continues to be assessed as effective, are immediately recognized in net income. Ineffectiveness is generally measured as the cumulative excess, if any, of the change in value of the hedging instrument over the change in value of the hedged item. See Notes 12 and 18 for additional information concerning hedging activity.
Realized and unrealized gains and losses from transacting in energy-related derivative instruments are primarily reported in the income statement in net gain (loss) from commodity hedging and trading activities. In accordance with accounting rules, upon settlement of physical derivative sales and purchase contracts that are marked-to-market in net income, related wholesale electricity revenues and fuel and purchased power costs are reported at approximated market prices, instead of the contract price. As a result, this noncash difference between market and contract prices is included in the operating revenues and fuel and purchased power costs and delivery fees line items of the income statement, with offsetting amounts included in net gain (loss) from commodity hedging and trading activities.
Revenue Recognition
We record revenue from electricity sales and delivery service under the accrual method of accounting. Revenues are recognized when electricity or delivery services are provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the revenues earned from the meter reading date to the end of the period (unbilled revenue).
Our reported revenues include, on a net basis, ERCOT electricity balancing transactions, which represent wholesale purchases and sales of electricity for real-time balancing purposes as measured in 15-minute intervals. As is industry practice, these purchases and sales with ERCOT, as the balancing energy clearinghouse agent, are reported net in the income statement. Balancing transactions are difficult to predict, with results varying from period to period between net revenues and net expense, and are reported as a component of revenues in the income statement.
Impairment of Long-Lived Assets
We evaluate long-lived assets (including intangible assets with finite lives) for impairment whenever indications of impairment exist. The carrying value of such assets is deemed to be impaired if the projected undiscounted cash flows are less than the carrying value. If there is such impairment, a loss would be recognized based on the amount by which the carrying value exceeds the fair value. Fair value is determined primarily by discounted cash flows, supported by available market valuations, if applicable. See Note 5 for details of the impairment of the natural gas-fueled generation facilities recorded in 2008.
Finite-lived intangibles identified as a result of purchase accounting are amortized over their estimated useful lives based on the expected realization of economic effects. See Note 3 to Financial Statements 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. The impairment tests performed are based on discounted cash flow analyses. See Note 3 for details of goodwill and intangible assets with indefinite lives, including discussion of goodwill and trade name intangible assets impairments recorded in 2009 and 2008.
In 2009, we changed the annual test date for goodwill and intangible assets with indefinite lives from October 1 to December 1. Management determined the new annual goodwill test date is preferable because of efficiencies gained by aligning the test with our annual budget and five-year plan processes in the fourth quarter. The change in the annual test date did not delay, accelerate or avoid an impairment charge, and retrospective application of this change in accounting principle did not affect previously reported results.
Amortization of Nuclear Fuel
Amortization of nuclear fuel is calculated on the units-of-production method and is reported as fuel costs.
Major Maintenance
Major maintenance costs incurred during generation plant outages and the costs of other maintenance activities are charged to expense as incurred and reported as operating costs.
Defined Benefit Pension Plans and Other Postretirement Employee Benefit Plans
We offer pension benefits based on either a traditional defined benefit formula or a cash balance formula and also offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from the company. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. The pension and OPEB accrued benefit obligations reported in the balance sheet are in accordance with accounting standards related to employers’ accounting for defined benefit pension and other postretirement plans. See Note 21 for additional information regarding pension and OPEB plans.
Stock-Based Incentive Compensation
Prior to the Merger, we provided discretionary awards payable in EFH Corp. common stock to qualified managerial employees under our shareholder-approved long-term incentive plans. In December 2007, our board of directors established our 2007 Stock Incentive Plan, which authorizes discretionary grants to directors, officers and qualified managerial employees of EFH Corp. or its affiliates of non-qualified stock options, stock appreciation rights, restricted shares, shares of common stock, the opportunity to purchase shares of common stock and other stock-based awards. Stock-based compensation expense is recognized over the vesting period based on the grant-date fair value of those awards. See Note 22 for information regarding stock-based incentive compensation.
Sales and Excise Taxes
Sales and excise taxes are accounted for as a “pass through” item on the balance sheet; i.e., the tax is billed to customers and recorded as trade accounts receivable with an offsetting amount recorded as a liability to the taxing jurisdiction.
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Franchise and Revenue-Based Taxes
Unlike sales and excise taxes, franchise and gross receipt taxes are not a “pass through” item. These taxes are assessed to us by state and local government bodies, based on revenues or kWh delivered, as a cost of doing business and are recorded as an expense. Rates charged to customers by us are intended to recover the franchise and gross receipt taxes, but we are not acting as an agent to collect the taxes from customers.
Income Taxes
We file a consolidated federal income tax return, and federal income taxes are calculated for our subsidiaries substantially as if the entities file separate income tax returns. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities. Effective with the sale of noncontrolling interests in Oncor (see Note 15), Oncor became a partnership for US federal income tax purposes, and we provide deferred income taxes on the difference between the book and tax basis of our investment in Oncor. Previously earned investment tax credits were deferred and amortized as a reduction of income tax expense over the estimated lives of the related properties. In connection with purchase accounting, the remaining unamortized investment tax credit amount related to unregulated businesses of $300 million was eliminated. Investment tax credits related to Oncor’s regulated operations will continue to be amortized over the lives of the related properties in accordance with regulatory treatment. Certain provisions of the accounting guidance for income taxes provide that regulated enterprises are permitted to recognize deferred taxes as regulatory tax assets or tax liabilities if it is probable that such amounts will be recovered from, or returned to, customers in future rates.
Accounting for Contingencies
Our financial results may be affected by judgments and estimates related to loss contingencies. Accruals for loss contingencies are recorded when management determines that it is probable that an asset has been impaired or a liability has been incurred and that such economic loss can be reasonably estimated. Such determinations are subject to interpretations of current facts and circumstances, forecasts of future events and estimates of the financial impacts of such events. See Note 13 for a discussion of contingencies.
Cash and Cash Equivalents
For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered to be cash equivalents.
We held an interest in The Reserve’s US Government Fund, which began liquidation proceedings in September 2008 due to the credit crisis and withdrawal demands. In September 2008, we attempted to redeem our interest, totaling $242 million, in the US Government Fund, but due to the liquidation process, the funds were not immediately made available; accordingly, such amount was reclassified from cash and cash equivalents to investment held in money market fund. We received $100 million of the funds in November 2008 and the remaining $142 million in January 2009.
Restricted Cash
The terms of certain agreements require the restriction of cash for specific purposes. At December 31, 2009, $1.135 billion of cash is restricted to support letters of credit. See Notes 12 and 25 for more details regarding this and other restricted cash.
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Property, Plant and Equipment
As a result of purchase accounting, carrying amounts of property, plant and equipment related to unregulated businesses on the Merger date were adjusted to estimated fair values. Subsequent additions are recorded at cost. Regulated properties at Oncor continue to be reported at original cost, which is considered to be fair value due to the cost-based regulated recovery and returns associated with those assets. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead, including payroll-related costs.
Depreciation of our property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties. As is common in the industry, the Predecessor historically recorded depreciation expense using composite depreciation rates that reflected blended estimates of the lives of major asset groups as compared to depreciation expense calculated on a component asset-by-asset basis. Effective with the Merger, depreciation expense for unregulated properties is calculated on a component asset-by-asset basis. Estimated depreciable lives are based on management’s estimates of the assets’ economic useful lives. See Note 25.
In accordance with the PUCT’s August 2009 order in Oncor’s rate review, the remaining net book value and anticipated removal cost of existing meters that are being replaced by advanced meters is being charged (amortized) to expense over an 11-year cost recovery period.
Capitalized Interest
Interest related to qualifying construction projects and qualifying software projects are capitalized in accordance with accounting guidance related to capitalization of interest cost. See Note 25.
Inventories
All inventories are reported at the lower of cost (on a weighted average basis) or market unless expected to be used in the generation of electricity. Also see discussion immediately below regarding environmental allowances and credits.
Environmental Allowances and Credits
Effective with the Merger, we began accounting for all environmental allowances and credits as identifiable intangible assets with finite lives that are subject to amortization. The recorded values of these intangible assets were originally established reflecting fair value determinations as of the date of the Merger under purchase accounting. Amortization expense associated with these intangible assets is recognized on a unit of production basis as the allowances or credits are consumed in generation operations. The environmental allowances and credits are assessed for impairment when conditions or events occur that could affect the carrying value of the assets. See Note 3 for details of impairment amounts recorded in 2008.
Regulatory Assets and Liabilities
The financial statements of our regulated electricity delivery operations reflect regulatory assets and liabilities under cost-based rate regulation in accordance with accounting standards related to the effect of certain types of regulation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. See Note 25 for details of the regulatory assets and liabilities.
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Investments
Investments in a nuclear decommissioning trust fund are carried at fair market value in the balance sheet. Investments in unconsolidated business entities over which we have significant influence but do not maintain effective control, generally representing ownership of at least 20% and not more than 50% of common equity, are accounted for under the equity method. Assets related to employee benefit plans represent investments held to satisfy deferred compensation liabilities and are recorded at market value. See Note 19 for details of investments.
Noncontrolling Interests
See Note 15 for discussion of accounting for the noncontrolling interests of Oncor.
Changes in Accounting Standards
In January 2010, the FASB issued guidance on disclosure about fair value measurements. The guidance requires new disclosures of transfers in and out of Levels 1 and 2 of the fair value hierarchy and separate disclosure about purchases, sales, issuances and settlements in Level 3 of the fair value hierarchy. The guidance also provides clarification on disclosures related to the level of disaggregation among assets and liabilities and to the inputs and valuation techniques used to measure fair value. This new guidance is effective for periods beginning January 1, 2010, except for the new disclosures about purchases, sales, issuances and settlements in Level 3, which are effective for periods beginning January 1, 2011. As this new guidance provides only disclosure requirements, the adoption will not have any effect on reported results of operations, financial condition or cash flows.
In August 2009, the FASB issued guidance on measuring fair value of liabilities, which provides clarification of fair value measurement when there is limited or no observable data available. The adoption of this guidance, as of October 1, 2009, did not have any effect on reported results of operations, financial condition or cash flows, and did not have any effect on the disclosures of the fair value of our debt provided in Note 17.
In June 2009, the FASB issued “TheFASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles,” which establishes theFASB Accounting Standards Codification™ (Codification) as the source of authoritative US GAAP recognized by the FASB to be applied to nongovernmental entities. The Codification was effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of the Codification did not affect reported results of operations, financial condition or cash flows.
In June 2009, the FASB issued new guidance that requires reconsideration of consolidation conclusions for all variable interest entities and other entities with which we are involved. This new guidance is effective January 1, 2010. The provisions of this guidance could result in different consolidation conclusions than reached under previous guidance, as the emphasis is on the power to direct the activities of the variable interest entity instead of risk and reward. We continue to evaluate the impact of this new guidance on our financial statements. In consideration of the ring-fencing measures in place, as discussed above under “Description of Business,” our evaluation may result in the deconsolidation of Oncor Holdings and its subsidiaries, which are the ring-fenced entities.
In June 2009, the FASB issued new guidance regarding accounting for transfers of financial assets that eliminates the concept of a qualifying special purpose entity, changes the requirements for derecognizing financial assets and requires additional disclosures. This new guidance is effective in the first quarter of 2010. We continue to evaluate the impact of this new guidance on our financial statements and footnote disclosures; however, we expect that our accounts receivable securitization program discussed in Note 11 will no longer be accounted for as a sale of accounts receivable as a result of the guidance, and the funding under the program will be reported as short-term borrowings. We do not expect this new guidance to impact the covenant-related ratio calculations in our debt agreements.
In May 2009, the FASB issued new guidance related to subsequent events that requires disclosure of the date through which we have evaluated subsequent events related to the financial statements being issued and the basis for that date. Our adoption of this guidance as of April 1, 2009 did not affect reported results of operations, financial condition or cash flows, and the required disclosure is provided above in “Basis of Presentation.”
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In April 2009, the FASB issued new guidance regarding determining fair value when the volume and level of activity for the asset or liability have significantly decreased or market transactions are not orderly. We adopted this guidance as of April 1, 2009. While this guidance did not change our fair value measurement techniques, it requires disclosures of additional detail of securities held in our nuclear decommissioning trust that are provided in Notes 16 and 19.
In April 2009, the FASB issued new guidance regarding the recognition and presentation of other-than-temporary impairments, which changed the guidance for recording impairment of investments in debt securities. Our adoption as of April 1, 2009 did not affect the accounting for our nuclear decommissioning trust fund because the trust balance has historically been reported at fair value, with changes in fair value of the trust resulting in changes in Oncor’s regulatory asset or liability related to the decommissioning cost.
In December 2008, the FASB issued new guidance for employers’ disclosures about postretirement benefit plan assets. This new guidance provides enhanced disclosures regarding how investment allocation decisions are made and certain aspects of fair value measurements on plan assets. The required disclosures are intended to provide transparency related to the types of assets and associated risks in an employer’s defined benefit pension or other postretirement employee benefits plan and events in the economy and markets that could have a significant effect on the value of plan assets. As this new guidance provides only disclosure requirements, our adoption as of December 31, 2009 did not have any effect on reported results of operations, financial condition or cash flows. The disclosures are provided in Note 21.
In March 2008, the FASB issued amended disclosure guidance for derivative instruments and hedging activities. This amended guidance enhances required disclosures regarding derivatives and hedging activities to enable investors to better understand their effects on an entity’s financial position, financial performance and cash flows. As this guidance provides only disclosure requirements, our adoption as of January 1, 2009 did not have any effect on reported results of operations or financial condition. The disclosures are provided in Note 18.
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| 2. | FINANCIAL STATEMENT EFFECTS OF THE MERGER |
As discussed in Note 1, the Merger was completed on October 10, 2007. The aggregate purchase price paid for the equity securities of EFH Corp. was $31.9 billion, which was financed by a combination of equity invested by the Sponsor Group and certain other investors and by borrowings under a senior secured credit facility and senior unsecured interim facilities. These facilities also funded the repayment and redemption of certain existing credit facilities and debt upon completion of the Merger. See Note 12 for a discussion of our debt.
The statements of consolidated income (loss) and cash flows for 2007 present Predecessor results from January 1 through October 10 and Successor results from October 11 through December 31.
Sources and Uses
The sources and uses of the funds for the Merger are summarized in the table below.
Sources of funds: | Uses of funds: | |||||||
| (billions of dollars) | ||||||||
Cash and other sources | $ | 0.3 | Equity purchase price (c) | $ | 31.9 | |||
TCEH credit facilities (Note 12) | 27.0 | Transaction costs (d) | 0.8 | |||||
EFH Corp. senior unsecured interim facility (a) | 4.5 | Repayment of existing debt | 5.3 | |||||
Equity contributions (b) | 8.3 | Restricted cash | 1.2 | |||||
Financing fees related to new facilities | 0.9 | |||||||
Total source of funds | $ | 40.1 | Total uses of funds | $ | 40.1 | |||
| (a) | Interim facility that was repaid with the proceeds from the issuance of the EFH Corp. Senior Notes that are discussed in Note 12. |
| (b) | Consists of equity contributions by the Sponsor Group and certain other investors. |
| (c) | Represents 461.2 million outstanding shares of EFH Corp. common stock multiplied by $69.25 per share. |
| (d) | Represents professional fees incurred by the Sponsor Group that were directly associated with the Merger and accounted for as part of the purchase price. |
Purchase Price Allocation
We accounted for the Merger under purchase accounting in accordance with the provisions of accounting standards related to business combinations, whereby the total purchase price of the transaction was allocated to our identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of the Merger date as summarized in the table below. The fair values were determined based upon assumptions related to future cash flows, discount rates, and asset lives as well as factors more unique to us, our industry and the competitive wholesale power market that include forward natural gas price curves and market heat rates, retail customer attrition rates, generation plant operating and construction costs, and the effect on generation facility values of lignite fuel reserves and mining capabilities using currently available information. As a result of cost-based regulatory rate-setting processes, the book value of the majority of Oncor’s assets and liabilities effectively represent fair value, and no adjustments to those regulated assets or liabilities were recorded. The excess of the purchase price over the fair value of net assets acquired was recorded as goodwill.
The goodwill amount recorded upon finalization of purchase accounting in 2008 totaled $23.2 billion. Management believes the drivers of the goodwill amount include the incremental value of the future cash flow potential of the baseload generation facilities, including facilities under construction, over the values assigned to those assets under purchase accounting rules, considering the market-pricing mechanisms and growth potential in the ERCOT market, as well as the value derived from the scale of the retail business. Management also believes that the goodwill reflects the value of the relatively stable, long-lived cash flows of the regulated business, considering the constructive regulatory environment and market growth potential. See Note 3 for disclosures related to goodwill, including an impairment recorded in the fourth quarter of 2008 and first quarter of 2009.
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The following table summarizes the components of the final purchase price allocation:
Equity purchase price | $ | 31,935 | |||
Transaction costs | 759 | ||||
Total purchase price | 32,694 | ||||
Property, plant and equipment | 28,088 | ||||
Intangible assets (Note 3) | 4,454 | ||||
Regulatory assets and deferred debits | 1,445 | ||||
Other assets | 5,187 | ||||
Total assets acquired | 39,174 | ||||
Short-term borrowings and long-term debt | 14,183 | ||||
Deferred tax liabilities | 7,706 | ||||
Other liabilities | 7,837 | ||||
Total liabilities assumed | 29,726 | ||||
Net identifiable assets acquired | 9,448 | ||||
Goodwill | $ | 23,246 | |||
The following table summarizes the change in the total amount of goodwill during 2008 as a result of purchase accounting:
Goodwill at December 31, 2007 | $ | 22,954 | ||||
Property, plant and equipment | 311 | |||||
Intangible assets | 30 | |||||
Regulatory assets – net | 2 | |||||
Other assets | 174 | |||||
Total assets acquired | 517 | |||||
Deferred income tax liabilities | (263 | ) | ||||
Other liabilities | 38 | |||||
Total liabilities assumed | (225 | ) | ||||
Net identifiable assets acquired | 292 | |||||
Goodwill at completion of purchase accounting | $ | 23,246 | ||||
The above changes relate largely to finalization of fair values of natural gas-fueled generation plants and amounts related to the Capgemini outsourcing agreement, as well as the effects on related deferred income tax balances.
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Accrued liabilities were recorded in purchase accounting for exit activities resulting from the Merger. Exit liabilities recorded related to the cancellation of the development of coal-fueled generation facilities discussed in Note 4, the exit of certain administrative activities and the termination of outsourcing arrangements with Capgemini under change of control provisions of such arrangements (see Note 20). The following table summarizes the changes to the exit liability:
| Competitive Electric segment | Regulated Delivery segment | Total | ||||||||||
Liability for exit activities as of October 11, 2007 | $ | 60 | $ | — | $ | 60 | ||||||
Liability for exit activities as of December 31, 2007 | 60 | — | 60 | |||||||||
Additions to liability (a) | 38 | 16 | 54 | |||||||||
Payments recorded against liability | (60 | ) | — | (60 | ) | |||||||
Liability for exit activities as of December 31, 2008 | 38 | 16 | 54 | |||||||||
Payments recorded against liability | (24 | ) | (4 | ) | (28 | ) | ||||||
Other adjustments to the liability (b) | (11 | ) | (10 | ) | (21 | ) | ||||||
Liability for exit activities as of December 31, 2009 (c) | $ | 3 | $ | 2 | $ | 5 | ||||||
| (a) | Additional amounts recorded upon finalization of purchase accounting. |
| (b) | Represents reversal of exit liabilities due primarily to a shorter than expected outsourcing services transition period. |
| (c) | Remaining accrual is expected to be settled in 2010, the targeted date to complete the transition of outsourced activities back to us or to service providers. |
Unaudited Pro Forma Financial Information
The following unaudited pro forma financial position and results of operations assume that the Merger-related transactions occurred on January 1, 2007. The unaudited pro forma information is provided for informational purposes only and is not necessarily indicative of what our results of operations would have been if the Merger-related transactions had occurred on that date, or what our results of operations will be for any future periods.
For the year ended December 31, 2007, unaudited pro forma revenues and net loss were $10.0 billion and $2.3 billion, respectively. Pro forma adjustments for the year ended December 31, 2007 consist of adjustments for the Predecessor period and consist of $473 million in depreciation and amortization expense (including amounts recognized in revenues or fuel and purchased power costs), $2.1 billion in interest expense and a $895 million income tax benefit.
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| 3. | GOODWILL AND IDENTIFIABLE INTANGIBLE ASSETS |
Goodwill
As discussed in Note 2, we accounted for the Merger under purchase accounting. The total goodwill amount recorded as a result of purchase accounting totaled $23.2 billion, representing the excess of the purchase price over the fair value of the tangible and identifiable intangible net assets acquired in the Merger; subsequently, impairment charges were recorded in the fourth quarter of 2008 and the first quarter of 2009 (discussed immediately below). Accounting guidance related to goodwill and other intangible assets requires that goodwill be assigned to “reporting units,” which management has determined to be the Competitive Electric segment and the Regulated Delivery segment, which are largely comprised of TCEH and Oncor, respectively. The original goodwill amounts assigned to the Competitive Electric segment of $18.3 billion and the Regulated Delivery segment of $4.9 billion were based on the enterprise values of those businesses at the closing date of the Merger and the completion of purchase accounting.
Reported goodwill as of December 31, 2009 totaled $14.3 billion, with $10.2 billion assigned to the Competitive Electric segment and $4.1 billion to the Regulated Delivery segment. Reported goodwill as of December 31, 2008 totaled $14.4 billion, with $10.3 billion assigned to the Competitive Electric segment and $4.1 billion to the Regulated Delivery segment. None of this goodwill balance is being deducted for tax purposes.
Goodwill and Trade Name Intangible Asset Impairments
The 2009 annual impairment testing performed as of October 1, and December 1, 2009 for goodwill and intangible assets with indefinite useful lives in accordance with accounting guidance for a change in annual impairment testing dates resulted in no impairment (see discussion in Note 1 regarding change in the annual impairment test date from October 1 to December 1). The goodwill testing determined that the estimated fair value (enterprise value) of the Regulated Delivery segment exceeded its carrying value by approximately 10% resulting in no additional testing being required and no impairment for the segment. Key assumptions in the valuation of the regulated business include discount rates, growth of the rate base and return on equity allowed by the regulatory authority. Cash flows of the regulated business are relatively stable and more predictable than the competitive business. The Competitive Electric segment carrying value exceeded its estimated enterprise value (by less than 10%), so the estimated enterprise value of the segment was compared to the estimated fair values of its operating assets and liabilities. This additional testing indicated that the implied goodwill amount exceeded the recorded goodwill amount, and thus no goodwill impairment was recorded. The estimated enterprise value of the Competitive Electric segment reflects the impact of the decline in forward natural gas prices on wholesale electricity prices. Because lower wholesale electricity prices also result in lower fair values of our generation assets, calculated implied goodwill was sufficient to support the recorded goodwill amount. Key variables in the tests included forward natural gas prices, electricity prices, market heat rates and discount rates, assumptions regarding each of which could have a significant effect on valuations. Because of the volatility of these factors, we cannot predict the likelihood of any future impairment.
In the first quarter of 2009, we recorded a $90 million goodwill impairment charge largely related to the Competitive Electric segment. This charge resulted from the completion of fair value calculations supporting the initial $8.860 billion goodwill impairment charge that was recorded in the fourth quarter of 2008 and consisted of an impairment of $8.0 billion related to the Competitive Electric segment and $860 million related to the Regulated Delivery segment. The impairment charge primarily reflected the dislocation in the capital markets during the fourth quarter of 2008 that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies. The impairment determination involved significant assumptions and judgments in estimating enterprise values of the Competitive Electric and Regulated Delivery segments and the fair values of their assets and liabilities. This cumulative $8.950 billion charge is the only goodwill impairment recorded since the Merger.
Also in the fourth quarter of 2008, we recorded a trade name intangible asset impairment charge totaling $481 million ($310 million after-tax). The impairment primarily arises from the increase in the discount rate used in estimating fair value as discussed above.
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Although the annual impairment test date for goodwill and intangible assets with indefinite lives set by management was October 1, management determined that in consideration of the continuing deterioration of securities values during the fourth quarter of 2008, an impairment testing trigger occurred subsequent to that test date; consequently, the impairment charges were based on estimated fair values at December 31, 2008. See Note 1 for discussion of the change of the annual impairment test date to December 1 in 2009.
The calculations supporting the impairment determination utilized models that took into consideration multiple inputs, including commodity prices, debt yields, equity prices of comparable companies and other inputs. Those models were generally used in developing long-term forward price curves for certain commodities and discount rates for determining fair values of our reporting units as well as certain individual assets and liabilities of those businesses. The fair value measurements resulting from such models are classified as Level 3 non-recurring fair value measurements consistent with accounting standards related to the determination of fair value (see Note 16).
Identifiable Intangible Assets
Identifiable intangible assets reported in the balance sheet are comprised of the following:
| Successor | ||||||||||||||||||
| As of December 31, 2009 | As of December 31, 2008 | |||||||||||||||||
| Gross Carrying Amount | Accumulated Amortization | Net | Gross Carrying Amount | Accumulated Amortization | Net | |||||||||||||
Retail customer relationship | $ | 463 | $ | 215 | $ | 248 | $ | 463 | $ | 130 | $ | 333 | ||||||
Favorable purchase and sales contracts | 700 | 374 | 326 | 700 | 249 | 451 | ||||||||||||
Capitalized in-service software | 490 | 167 | 323 | 255 | 116 | 139 | ||||||||||||
Environmental allowances and credits | 992 | 212 | 780 | 994 | 121 | 873 | ||||||||||||
Land easements | 188 | 72 | 116 | 184 | 69 | 115 | ||||||||||||
Mining development costs | 32 | 5 | 27 | 19 | 2 | 17 | ||||||||||||
Total intangible assets subject to amortization | $ | 2,865 | $ | 1,045 | 1,820 | $ | 2,615 | $ | 687 | 1,928 | ||||||||
Trade name (not subject to amortization) | 955 | 955 | ||||||||||||||||
Mineral interests (not currently subject to amortization) | 101 | 110 | ||||||||||||||||
Total intangible assets | $ | 2,876 | $ | 2,993 | ||||||||||||||
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Details of amortization expense related to intangible assets (including income statement line item in which the amortization is included) follows:
| Successor | Predecessor | |||||||||||||||||
Intangible Asset (Income Statement line) | Segment | Useful lives at December 31, 2009 (weighted average in years) | Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | ||||||||||||
Retail customer relationship (Depreciation and amortization) | Competitive Electric | 4 | $ | 85 | $ | 51 | $ | 79 | $ | — | ||||||||
Favorable purchase and sales contracts (Operating revenues/fuel, purchased power costs and delivery fees) | Competitive Electric | 12 | 125 | 168 | 72 | — | ||||||||||||
Capitalized in-service software (Depreciation and amortization) | All | 5 | 53 | 44 | 8 | 23 | ||||||||||||
Environmental allowances and credits (Fuel, purchased power costs and delivery fees) | Competitive Electric | 28 | 91 | 102 | 20 | — | ||||||||||||
Land easements (Depreciation and amortization) | Regulated Delivery | 67 | 3 | 3 | — | 2 | ||||||||||||
Mining development costs (Depreciation and amortization) | Competitive Electric | 5 | 3 | 1 | — | — | ||||||||||||
Total amortization expense | $ | 360 | $ | 369 | $ | 179 | $ | 25 | ||||||||||
Separately identifiable and previously unrecognized intangible assets acquired and recorded as part of purchase accounting for the Merger are described as follows:
| • | Retail Customer Relationship– Retail customer relationship intangible asset represents the estimated fair value of the non-contracted customer base and is being amortized using an accelerated method based on customer attrition rates and reflecting the expected pattern in which economic benefits are realized over their estimated useful life. |
| • | Favorable Purchase and Sales Contracts– Favorable purchase and sales contracts intangible asset primarily represents the above market value, based on observable prices or estimates, of commodity contracts for which: (i) we have made the “normal” purchase or sale election allowed by accounting standards related to derivative instruments and hedging transactions or (ii) the contracts did not meet the definition of a derivative. The amortization periods of these intangible assets are based on the terms of the contracts. Unfavorable purchase and sales contracts are recorded as other noncurrent liabilities and deferred credits (see Note 25). |
| • | Trade name– The trade name intangible asset represents the estimated fair value of the TXU Energy trade name, and was determined to be an indefinite-lived asset not subject to amortization. This intangible asset will be evaluated for impairment at least annually in accordance with accounting guidance related to goodwill and other intangible assets. See above for discussion of an impairment charge recorded in 2008. |
| • | Environmental Allowances and Credits –This intangible asset represents the fair value, based on observable prices or estimates, of environmental credits, substantially all of which were expected to be used in our power generation activities. These credits are amortized utilizing a units-of-production method. |
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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. Since the D.C. Circuit Court did not prescribe a deadline for this revision, at this time, we cannot predict how or when the EPA may revise CAIR.
Estimated Amortization of Intangible Assets– The estimated aggregate amortization expense of intangible assets for each of the next five fiscal years is as follows:
Year | Amortization Expense | ||
2010 | $ | 278 | |
2011 | 210 | ||
2012 | 166 | ||
2013 | 147 | ||
2014 | 133 | ||
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| 4. | CHARGES RELATED TO CANCELLED DEVELOPMENT OF COAL-FUELED GENERATION FACILITIES |
In 2007, we recorded a net charge totaling $757 million ($492 million after-tax), substantially all of which was in the Predecessor period, in connection with the February 2007 suspension of the development of eight coal-fueled generation units. This decision and subsequent terminations of equipment orders required an evaluation of the recoverability of recorded assets associated with the development program. The net charge included $705 million for the impairment of construction work-in-process asset balances (primarily pre-construction development costs), $79 million for costs arising from terminations of equipment orders, $29 million for the write-off of deferred financing costs and a $57 million gain on sale (in early October 2007) of two in-process boilers. Additional charges totaling $12 million ($8 million after-tax) were recorded in 2008, which primarily represented costs for transportation and storage of materials.
The construction work-in-process asset balances totaled $871 million prior to the writedown and included progress payments made and accruals for amounts due to equipment suppliers, based on percentage of completion estimates, engineering and design services costs, site preparation expenditures, internal salary and related overhead costs for personnel engaged directly in construction management activities and capitalized interest. The remaining carrying value of assets related to the program at December 31, 2009 totaled $77 million and represented estimated recovery amounts, using a probability-weighted methodology, from equipment salvage and potential resale activities. Cumulative net cash proceeds through December 31, 2009 from the sale of the impaired assets totaled $172 million.
We have terminated all of the equipment orders, with the exception of one purchase order for a boiler that we are attempting to sell, and the air permit applications related to the eight units were formally withdrawn from the TCEQ in October 2007 after the close of the Merger. The net charges arising from cancellation of this development program have been classified in other deductions and are reported in the results of the Competitive Electric segment.
| 5. | IMPAIRMENT OF NATURAL GAS-FUELED GENERATION FACILITIES |
In 2008, we performed an evaluation of our natural gas-fueled generation facilities for impairment. The impairment test was triggered by a determination that it was more likely than not that certain generation units would be retired or mothballed (idled) earlier than previously expected. The natural gas-fueled generation units are generally operated to meet peak demands for electricity and all such facilities are tested for impairment as an asset group. As a result of the evaluation, it was determined that an impairment existed, and a charge of $229 million ($147 million after-tax) was recorded to write down the assets to fair value of approximately $28 million, which was determined based on discounted estimated future cash flows. The impairment was reported in other deductions in the Competitive Electric segment.
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| 6. | STIPULATION APPROVED BY THE PUCT |
Oncor and Texas Holdings agreed to the terms of a stipulation, which was conditional upon completion of the Merger, with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. In February 2008, the PUCT entered an order approving the stipulation. The PUCT issued a final order on rehearing in April 2008 that has been appealed to 200th District Court of Travis County, Texas. The parties to the appeal have agreed to a schedule that would result in a hearing in June 2010.
In addition to commitments Oncor made in its filings in the PUCT review, the stipulation included the following provisions, among others:
| • | Oncor provided a one-time $72 million refund to its REP customers in the September 2008 billing cycle. The refund was in the form of a credit on distribution fee billings. The liability for the refund was recorded as part of purchase accounting. |
| • | Consistent with the 2006 cities rate settlement (see Note 7), Oncor filed a system-wide rate case in June 2008 based on a test-year ended December 31, 2007. In August 2009, the PUCT issued a final order on this rate case. See Note 25. |
| • | Oncor agreed not to request recovery of approximately $56 million of regulatory assets related to self-insurance reserve costs and 2002 restructuring expenses. These regulatory assets were eliminated as part of purchase accounting. |
| • | The dividends paid by Oncor will be limited through December 31, 2012, to an amount not to exceed Oncor’s net income (determined in accordance with GAAP, subject to certain defined adjustments) for the period beginning October 11, 2007 and ending December 31, 2012, and are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. |
| • | Oncor committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. |
| • | Oncor committed to an additional $100 million in spending over the five-year period ending December 31, 2012 on demand-side management or other energy efficiency initiatives. These additional expenditures will not be recoverable in rates, and this amount was recorded as a regulatory liability as part of purchase accounting and consistent with accounting standards related to the effect of certain types of regulation. |
| • | If Oncor’s credit rating is below investment grade with two or more rating agencies, TCEH will post a letter of credit in an amount of $170 million to secure TXU Energy’s payment obligations to Oncor. |
| • | Oncor agreed not to request recovery of the $4.9 billion of goodwill resulting from purchase accounting or any future impairment of the goodwill in its rates. |
| 7. | CITIES RATE SETTLEMENT IN 2006 |
In January 2006, Oncor agreed with a steering committee representing 108 cities in Texas (Cities) to defer the filing of a system-wide rate case with the PUCT to no later than July 1, 2008 (based on a test year ending December 31, 2007). Oncor filed the rate case with the PUCT in June 2008, and the PUCT issued a final order on the case in 2009. Oncor extended the benefits of the agreement to 292 nonlitigant cities. The agreements provided that Oncor would make payments to participating cities totaling approximately $70 million, including incremental franchise taxes.
This amount was recognized in earnings over the period from May 2006 through June 2008. Amounts recognized totaled $11 million in 2009, $23 million in 2008, $8 million for the period October 11, 2007 through December 31, 2007 and $25 million for the period January 1, 2007 through October 10, 2007, of which $2 million, $13 million, $6 million and $20 million, respectively, were reported in other deductions (see Note 10), with the remainder reported in franchise and revenue-based taxes. Amounts recognized in 2009 represented extension of benefits per the agreement related to the timing of completion of the rate case.
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| 8. | ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES |
Effective January 1, 2007, we adopted accounting guidance related to uncertain tax positions. This guidance requires that all tax positions subject to uncertainty be reviewed and assessed with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable. We applied updated guidance to determine if each tax position was effectively settled for the purpose of recognizing previously uncertain tax positions. We completed our review and assessment of uncertain tax positions and in the 2007 Predecessor period recorded a net benefit to retained earnings and a decrease to noncurrent liabilities of $33 million in accordance with the new accounting rule.
We file income tax returns in US federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. Examinations of our income tax returns for the years ending prior to January 1, 2003 are complete, but the tax years 1997 to 2002 remain in appeals with the IRS. The conclusion of issues contested from the 1997 to 2002 audit, including matters related to TXU Europe, is not expected to occur prior to 2011. In 2008, we were notified of the commencement of an IRS audit of tax years 2003 to 2006. The audit is expected to require two years to complete. Texas franchise and margin tax returns are under examination or still open for examination for tax years beginning after 2002.
In 2008, we participated in negotiations with the IRS regarding the 2002 worthlessness loss associated with our discontinued Europe business, and we reduced the liability for uncertain tax positions in accordance with accounting guidance. The reduction in the liability of approximately $375 million was largely offset by a reduction of deferred tax assets related to alternative minimum tax.
We classify interest and penalties related to uncertain tax positions as current income tax expense. Amounts recorded related to interest and penalties totaled $42 million in 2009, $88 million in 2008, including $29 million recorded as goodwill, $12 million for the period October 11, 2007 through December 31, 2007 and $43 million for the period January 1, 2007 through October 10, 2007 (all amounts after tax).
Noncurrent liabilities included a total of $361 million and $198 million in accrued interest at December 31, 2009 and 2008, respectively. Effective in 2009, the federal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferred income taxes. Such amounts were previously reported net as a reduction of the liability for uncertain tax positions.
The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in the consolidated balance sheet, during the years ended December 31, 2009 and 2008:
| 2009 | 2008 | |||||||
Balance at January 1, excluding interest and penalties | $ | 1,583 | $ | 1,834 | ||||
Additions based on tax positions related to prior years | 71 | 124 | ||||||
Reductions based on tax positions related to prior years | (82 | ) | (451 | ) | ||||
Additions based on tax positions related to the current year | 66 | 33 | ||||||
Settlements with taxing authorities | — | 43 | ||||||
Reductions related to the lapse of the tax statute of limitations | — | — | ||||||
Balance at December 31, excluding interest and penalties | $ | 1,638 | $ | 1,583 | ||||
Of the balance at December 31, 2009, $1.474 billion represents tax positions for which the uncertainty relates to the timing of recognition in tax returns. The disallowance of such positions would not affect the effective tax rate, but would accelerate the payment of cash to the taxing authority to an earlier period.
With respect to tax positions for which the ultimate deductibility is uncertain (permanent items), should we sustain such positions on income tax returns previously filed, liabilities recorded would be reduced by $164 million, resulting in increased income from continuing operations and a favorable impact on the effective tax rate.
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We filed a claim in 2006 for refund of income taxes and related interest paid in 2005 associated with IRS audits of 1993 and 1994 tax returns of a discontinued operation. The expected refund was recognized in the adoption of accounting guidance related to uncertain tax positions. We received the refund, totaling $98 million, in February 2009.
We do not expect the total amount of liabilities recorded related to uncertain tax positions will significantly increase or decrease within the next 12 months.
| 9. | INCOME TAXES |
The components of our income tax expense (benefit) applicable to continuing operations are as follows:
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Current: | ||||||||||||||||||
US Federal | $ | 64 | $ | (46 | ) | $ | 52 | $ | 400 | |||||||||
State | 51 | 52 | 10 | 20 | ||||||||||||||
Total | 115 | 6 | 62 | 420 | ||||||||||||||
Deferred: | ||||||||||||||||||
US Federal | 256 | (482 | ) | (722 | ) | 12 | ||||||||||||
State | 1 | 10 | (12 | ) | (108 | ) | ||||||||||||
Total | 257 | (472 | ) | (734 | ) | (96 | ) | |||||||||||
Amortization of investment tax credits | (5 | ) | (5 | ) | (1 | ) | (15 | ) | ||||||||||
Total | $ | 367 | $ | (471 | ) | $ | (673 | ) | $ | 309 | ||||||||
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Reconciliation of income taxes computed at the US federal statutory rate to income tax expense:
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Income (loss) from continuing operations before income taxes | $ | 775 | $ | (10,469 | ) | $ | (2,034 | ) | $ | 1,008 | ||||||||
Income taxes at the US federal statutory rate of 35% | $ | 271 | $ | (3,664 | ) | $ | (712 | ) | $ | 353 | ||||||||
Nondeductible goodwill impairment | 32 | 3,101 | — | — | ||||||||||||||
Lignite depletion allowance | (18 | ) | (29 | ) | (5 | ) | (30 | ) | ||||||||||
Production activities deduction | — | — | 10 | (10 | ) | |||||||||||||
Amortization of investment tax credits — net of deferred income tax effect | (5 | ) | (5 | ) | (1 | ) | (12 | ) | ||||||||||
Amortization (under regulatory accounting) of statutory rate changes | 5 | 2 | — | 2 | ||||||||||||||
Medicare subsidy — other postretirement employee benefits | (7 | ) | (6 | ) | (2 | ) | (6 | ) | ||||||||||
Nondeductible interest expense | 13 | 11 | 1 | — | ||||||||||||||
Nondeductible losses (earnings) on benefit plans | (1 | ) | 9 | (1 | ) | (6 | ) | |||||||||||
Texas margin tax, net of federal tax benefit | 30 | 39 | (3 | ) | 16 | |||||||||||||
Texas margin tax — deferred tax adjustment | — | — | — | (70 | ) | |||||||||||||
Nondeductible merger transaction costs | — | — | 23 | — | ||||||||||||||
Deferred tax adjustments | — | — | — | 25 | ||||||||||||||
Accrual of interest, net of federal tax benefit | 42 | 59 | 12 | 43 | ||||||||||||||
Other, including audit settlements | 5 | 12 | 5 | 4 | ||||||||||||||
Income tax expense (benefit) | $ | 367 | $ | (471 | ) | $ | (673 | ) | $ | 309 | ||||||||
Effective tax rate | 47.4 | % | 4.5 | % | 33.1 | % | 30.7 | % | ||||||||||
Texas Margin Tax
In May 2006, the Texas legislature enacted a new law that reformed the Texas franchise tax system and replaced it with a new tax system, referred to as the Texas margin tax. The Texas margin tax has been determined to be an income tax for accounting purposes. In June 2007, an amendment to this law was enacted that included clarifications and technical changes to the provisions of the tax calculation. In the 2007 Predecessor period, we recorded a deferred tax benefit of $70 million, essentially all of which related to changes in the rate at which a tax credit is calculated as specified in the new law. Of the total $70 million deferred tax benefit, $32 million was recognized in the Competitive Electric segment results and $38 million was recognized in the Corporate and Other nonsegment results.
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Deferred Income Tax Balances
Deferred income taxes provided for temporary differences based on tax laws in effect at December 31, 2009 and 2008 balance sheet dates are as follows:
| Successor | ||||||||||||||||||||
| December 31, 2009 | December 31, 2008 | |||||||||||||||||||
| Total | Current | Noncurrent | Total | Current | Noncurrent | |||||||||||||||
Deferred Income Tax Assets | ||||||||||||||||||||
Alternative minimum tax credit carryforwards | $ | 438 | $ | — | $ | 438 | $ | 447 | $ | — | $ | 447 | ||||||||
Employee benefit liabilities | 206 | 22 | 184 | 173 | 33 | 140 | ||||||||||||||
Net operating loss (NOL) carryforwards | 422 | — | 422 | 523 | — | 523 | ||||||||||||||
Unfavorable purchase and sales contracts | 249 | — | 249 | 259 | — | 259 | ||||||||||||||
Accrued interest | 211 | — | 211 | — | — | — | ||||||||||||||
Other | 351 | 13 | 338 | 260 | 44 | 216 | ||||||||||||||
Total | 1,877 | 35 | 1,842 | 1,662 | 77 | 1,585 | ||||||||||||||
Deferred Income Tax Liabilities | ||||||||||||||||||||
Property, plant and equipment | 4,141 | — | 4,141 | 4,375 | — | 4,375 | ||||||||||||||
Basis difference in Oncor partnership (a) | 1,369 | — | 1,369 | 1,333 | — | 1,333 | ||||||||||||||
Commodity contracts and interest rate swaps | 1,325 | 30 | 1,295 | 645 | 31 | 614 | ||||||||||||||
Identifiable intangible assets | 921 | — | 921 | 1,049 | — | 1,049 | ||||||||||||||
Debt fair value discounts | 184 | — | 184 | 257 | — | 257 | ||||||||||||||
Other | 63 | — | 63 | 26 | 2 | 24 | ||||||||||||||
Total | 8,003 | 30 | 7,973 | 7,685 | 33 | 7,652 | ||||||||||||||
Net Deferred Income Tax (Asset) Liability | $ | 6,126 | $ | (5 | ) | $ | 6,131 | $ | 6,023 | $ | (44 | ) | $ | 6,067 | ||||||
| (a) | See Note 14. |
At December 31, 2009 we had $438 million of alternative minimum tax credit carryforwards (AMT) available to offset future tax payments. The AMT credit carryforwards have no expiration date. At December 31, 2009, we had net operating loss (NOL) carryforwards for federal income tax purposes of $1.206 billion that expire between 2023 and 2028. The NOL carryforwards can be used to offset future taxable income. We expect to utilize all of our NOL carryforwards prior to their expiration dates.
The component of deferred income tax liabilities referred to as “basis difference in Oncor partnership” arose as a result of the sale of noncontrolling interests in Oncor (see Note 15) at which time Oncor became a partnership for US federal income tax purposes. The amount of this basis difference at the date of the transaction represented our interest (approximately 80%) in the net deferred tax liabilities related to Oncor’s individual operating assets and liabilities. The remaining net deferred tax liabilities associated with Oncor ($321 million at December 31, 2009) that are attributable to the noncontrolling interests have been reclassified as other noncurrent liabilities (see Note 25).
The income tax effects of the components included in accumulated other comprehensive income at December 31, 2009 and 2008 totaled a net deferred tax asset of $165 million and $207 million, respectively.
See Note 8 for discussion regarding accounting for uncertain tax positions.
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| 10. | OTHER INCOME AND DEDUCTIONS |
| Successor | Predecessor | ||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | ||||||||||||
Other income: | |||||||||||||||
Accretion of adjustment (discount) of regulatory assets resulting from purchase accounting (Note 25) | $ | 39 | $ | 44 | $ | 10 | $ | — | |||||||
Amortization of gain on sale of TXU Fuel (a) | — | — | — | 36 | |||||||||||
Debt extinguishment gain (Note 12) | 87 | — | — | — | |||||||||||
Reversal of reserves recorded in purchase accounting (b) | 44 | — | — | — | |||||||||||
Fee received related to interest rate swap/commodity hedge derivative agreement (c) (Note 18) | 6 | — | — | — | |||||||||||
Insurance recoveries (d) | — | 21 | — | ��� | |||||||||||
Net gain on sale of other properties and investments | 4 | 4 | 1 | 4 | |||||||||||
Reduction of insurance reserves related to discontinued operations | — | — | 1 | 7 | |||||||||||
Penalty received for nonperformance under a coal transportation agreement | — | — | — | 6 | |||||||||||
Mineral rights royalty income | 6 | 4 | 1 | 8 | |||||||||||
Other | 18 | 7 | 1 | 8 | |||||||||||
Total other income | $ | 204 | $ | 80 | $ | 14 | $ | 69 | |||||||
Other deductions: | |||||||||||||||
Impairment of trade name intangible asset (Note 3) | $ | — | $ | 481 | $ | — | $ | — | |||||||
Impairment of emission allowances intangible assets (Note 3) | — | 501 | — | — | |||||||||||
Charge for impairment of natural gas-fueled generation facilities (Note 5) | — | 229 | — | — | |||||||||||
Impairment of land (e) | 34 | — | — | — | |||||||||||
Charge related to Lehman bankruptcy (f) | — | 26 | — | — | |||||||||||
Write-off of regulatory assets (Note 25) | 25 | — | — | — | |||||||||||
Professional fees incurred related to the Merger (g) | — | 14 | 51 | 39 | |||||||||||
Net charges related to cancelled development of generation facilities (Note 4) | 6 | 12 | 2 | 755 | |||||||||||
Severance charges | 7 | — | — | — | |||||||||||
Charge related to termination of rail car lease (h) | — | — | — | 10 | |||||||||||
Other asset writeoffs (i) | 5 | 2 | — | 34 | |||||||||||
Credit related to impaired leases (j) | — | — | — | (48 | ) | ||||||||||
Costs related to 2006 cities rate settlement (Note 7) | 2 | 13 | 6 | 20 | |||||||||||
Litigation/regulatory settlements | 3 | 10 | — | 5 | |||||||||||
Expenses related to cancelled joint venture at Oncor | — | — | — | 12 | |||||||||||
Other | 15 | 13 | 2 | 14 | |||||||||||
Total other deductions | $ | 97 | $ | 1,301 | $ | 61 | $ | 841 | |||||||
| (a) | As part of the 2004 sale of the assets of TXU Fuel, TCEH entered into a transportation agreement with the new owner, intended to be market-price based, to transport natural gas to TCEH’s generation plants. Because of the continuing involvement in the business through the transportation agreement, the pretax gain of $375 million related to the sale was deferred and being recognized over the eight-year life of the transportation agreement, and the business was not accounted for as a discontinued operation. The remaining $218 million deferred gain was eliminated as part of purchase accounting related to the Merger. Reported in Corporate and Other activities. |
| (b) | Includes $23 million for reversal of a use tax accrual, related to periods prior to the Merger, due to a state ruling in 2009 (reported in Competitive Electric segment) and $21 million for reversal of excess exit liabilities recorded in connection with the termination of outsourcing arrangements (see Notes 2 and 20) (reported in Competitive Electric ($11 million) and Regulated Delivery segments ($10 million)). |
| (c) | Reported in Competitive Electric segment. |
| (d) | Represents insurance recovery for damage to mining equipment. Reported in Competitive Electric segment. |
| (e) | Impairment of land expected to be sold in the next 12 months. Reported in Competitive Electric segment. |
| (f) | Represents reserve established against amounts due (excluding termination related costs) from subsidiaries of Lehman Brothers Holdings Inc. (Lehman) arising from commodity hedging and trading activities. There are no open positions with these subsidiaries. Reported in Competitive Electric segment. |
| (g) | Includes post-Merger consulting expenses related to optimizing business performance. Reported in Corporate and Other activities. |
| (h) | Represents costs associated with termination and refinancing of a rail car lease. Reported in Competitive Electric segment. |
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| (i) | Predecessor period includes $30 million of previously deferred costs, consisting primarily of professional fees for tax, legal and other advisory services, in connection with certain previously anticipated strategic transactions (including expected financings) that were no longer expected to be consummated as a result of the Merger. Reported in Corporate and Other activities. |
| (j) | In 2004, we recorded a charge of $157 million for leases of certain natural gas-fueled combustion turbines, net of estimated sublease revenues, that were no longer operated for our own benefit. In the third quarter of 2007, a $48 million reduction in the related liability was recorded to reflect new subleases entered into in October 2007 (reported in the Competitive Electric segment results). The remaining $59 million liability was eliminated as part of purchase accounting as we intend to operate these assets for our own benefit. |
| 11. | TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM |
TXU Energy participates in an accounts receivable securitization program, the activity under which is accounted for as a sale of accounts receivable in accordance with transfers and servicing accounting standards (see Note 1 for discussion of a new accounting standard effective in the first quarter of 2010). Under the program, TXU Energy (originator) sells trade accounts receivable to TXU Receivables Company, which is a special purpose entity created for the purpose of purchasing receivables from the originator and is a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp. TXU Receivables Company sells undivided interests in the purchased accounts receivable for cash to special purpose entities established by financial institutions (the funding entities). As discussed below, Oncor also participated in the program prior to the Merger.
The maximum amount currently available under the accounts receivable securitization program is $700 million, and program funding totaled $383 million at December 31, 2009. Under the terms of the program, available funding was reduced by the total of $83 million of customer deposits held by the originator at December 31, 2009 because TCEH’s credit ratings were lower than Ba3/BB-.
All new trade receivables under the program generated by the originator are continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Changes in the amount of funding under the program, through changes in the amount of undivided interests sold by TXU Receivables Company, reflect seasonal variations in the level of accounts receivable, changes in collection trends and other factors such as changes in sales prices and volumes. TXU Receivables Company has issued subordinated notes payable to the originator for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to the originator that was funded by the sale of the undivided interests. The balance of the subordinated notes payable, which is eliminated in consolidation, totaled $463 million and $268 million at December 31, 2009 and 2008, respectively.
The discount from face amount on the purchase of receivables from the originator principally funds program fees paid to the funding entities. The program fees, which are also referred to as losses on sale of the receivables under transfers and servicing accounting standards, consist primarily of interest costs on the underlying financing. The discount also funds a servicing fee paid by TXU Receivables Company to EFH Corporate Services Company (Service Co.), a direct wholly-owned subsidiary of EFH Corp., which provides recordkeeping services and is the collection agent for the program.
Program fee amounts, which are reported in SG&A expenses, were as follows:
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Program fees | $ | 12 | $ | 25 | $ | 9 | $ | 32 | ||||||||||
Program fees as a percentage of average funding (annualized) | 2.4 | % | 5.2 | % | 9.5 | % | 6.4 | % | ||||||||||
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The trade accounts receivable balance reported in the December 31, 2009 consolidated balance sheet includes $846 million face amount of retail trade accounts receivable sold net of proceeds from the sale of undivided interests in those receivables totaling $383 million. Funding under the program decreased $33 million in 2009, increased $53 million in 2008 and decreased $264 million in 2007. Funding increases or decreases under the program are reflected as operating cash flow activity in the statement of cash flows. The carrying amount of the retained interests in the accounts receivable balance approximated fair value due to the short-term nature of the collection period.
In connection with the Merger, the accounts receivable securitization program was amended. Concurrently with the amendment, the financial institutions required that Oncor repurchase all of the receivables it had previously sold to TXU Receivables Company, which totaled $254 million. Oncor funded such repurchases through borrowings under its credit facility of $113 million, and a related subordinated note receivable from TXU Receivables Company in the amount of $141 million was canceled. Amounts related to Oncor’s trade accounts receivable for the period from January 1, 2007 through October 10, 2007 totaled $6 million in program fees and $27 million in operating cash flows provided, exclusive of the $113 million used by Oncor to repurchase its receivables at the time of the Merger.
Activities of TXU Receivables Company were as follows:
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Cash collections on accounts receivable | $ | 6,125 | $ | 6,393 | $ | 1,538 | $ | 6,251 | ||||||||||
Face amount of new receivables purchased | (6,287 | ) | (6,418 | ) | (1,194 | ) | (6,628 | ) | ||||||||||
Discount from face amount of purchased receivables | 14 | 29 | 9 | 35 | ||||||||||||||
Program fees paid to funding entities | (12 | ) | (25 | ) | (9 | ) | (32 | ) | ||||||||||
Servicing fees paid to Service Co. for recordkeeping and collection services | (2 | ) | (4 | ) | (1 | ) | (3 | ) | ||||||||||
Increase (decrease) in subordinated notes payable | 195 | (28 | ) | (120 | ) | 305 | ||||||||||||
Oncor’s repurchase of receivables previously sold | — | — | 113 | — | ||||||||||||||
Operating cash flows used by (provided to) originators under the program | $ | 33 | $ | (53 | ) | $ | 336 | $ | (72 | ) | ||||||||
The program, which expires in October 2013, may be terminated upon the occurrence of a number of specified events, including if the delinquency ratio (delinquent for 31 days) for the sold receivables, the default ratio (delinquent for 91 days or deemed uncollectible), the dilution ratio (reductions for discounts, disputes and other allowances) or the days collection outstanding ratio exceed stated thresholds, and the funding entities do not waive such event of termination. The thresholds apply to the entire portfolio of sold receivables. In addition, the program may be terminated if TXU Receivables Company or the EFH Corp. subsidiary acting as collection agent defaults in any payment with respect to debt in excess of $50,000 in the aggregate for such entities, or if TCEH, any affiliate of TCEH acting as collection agent other than the EFH Corp. subsidiary, any parent guarantor of the originator or the originator shall default in any payment with respect to debt (other than hedging obligations) in excess of $200 million in the aggregate for such entities. As of December 31, 2009, there were no such events of termination.
Upon termination of the program, liquidity would be reduced as collections of sold receivables would be used by TXU Receivables Company to repurchase the undivided interests from the funding entities instead of purchasing new receivables. The level of cash flows would normalize in approximately 16 to 30 days.
The subordinated notes issued by TXU Receivables Company are subordinated to the undivided interests of the funding entities in the purchased receivables.
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Trade Accounts Receivable
| Successor | ||||||||
| December 31, | ||||||||
| 2009 | 2008 | |||||||
Gross wholesale and retail trade accounts receivable | $ | 1,726 | $ | 1,705 | ||||
Undivided interests in retail accounts receivable sold by TXU Receivables Company | (383 | ) | (416 | ) | ||||
Allowance for uncollectible accounts | (83 | ) | (70 | ) | ||||
Trade accounts receivable — reported in balance sheet | $ | 1,260 | $ | 1,219 | ||||
Gross trade accounts receivable at December 31, 2009 and 2008 included unbilled revenues of $546 million and $505 million, respectively.
Allowance for Uncollectible Accounts Receivable
Predecessor: | ||||
Allowance for uncollectible accounts receivable as of December 31, 2006 | $ | 13 | ||
Increase for bad debt expense | 46 | |||
Decrease for account write-offs | (54 | ) | ||
Changes related to receivables sold | 26 | |||
Allowance for uncollectible accounts receivable as of October 10, 2007 | 31 | |||
Successor: | ||||
Allowance for uncollectible accounts receivable as of October 11, 2007 | 31 | |||
Increase for bad debt expense | 13 | |||
Decrease for account write-offs | (12 | ) | ||
Allowance for uncollectible accounts receivable as of December 31, 2007 | 32 | |||
Increase for bad debt expense | 81 | |||
Decrease for account write-offs | (69 | ) | ||
Charge related to Lehman bankruptcy | 26 | |||
Allowance for uncollectible accounts receivable as of December 31, 2008 | 70 | |||
Increase for bad debt expense | 113 | |||
Decrease for account write-offs | (99 | ) | ||
Other | (1 | ) | ||
Allowance for uncollectible accounts receivable as of December 31, 2009 | $ | 83 | ||
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| 12. | SHORT-TERM BORROWINGS AND LONG-TERM DEBT |
Short-Term Borrowings
At December 31, 2009, we had outstanding short-term borrowings of $1.569 billion at a weighted average interest rate of 2.50%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $953 million for TCEH and $616 million for Oncor.
At December 31, 2008, we had outstanding short-term borrowings of $1.237 billion at a weighted average interest rate of 3.41%, excluding certain customary fees, at the end of the period. Short-term borrowings under credit facilities totaled $900 million for TCEH and $337 million for Oncor.
Credit Facilities
Our credit facilities with cash borrowing and/or letter of credit availability at December 31, 2009 are presented below. The facilities are all senior secured facilities of the authorized borrower.
| At December 31, 2009 | ||||||||||||||
Authorized Borrowers and Facility | Maturity Date | Facility Limit | Letters of Credit | Cash Borrowings | Availability | |||||||||
TCEH Revolving Credit Facility (a) | October 2013 | $ | 2,700 | $ | — | $ | 953 | $ | 1,721 | |||||
TCEH Letter of Credit Facility (b) | October 2014 | 1,250 | — | 1,250 | — | |||||||||
Subtotal TCEH (c) | $ | 3,950 | $ | — | $ | 2,203 | $ | 1,721 | ||||||
TCEH Commodity Collateral Posting Facility (d) | December 2012 | Unlimited | $ | — | $ | — | Unlimited | |||||||
Oncor Revolving Credit Facility (e) | October 2013 | $ | 2,000 | $ | — | $ | 616 | $ | 1,262 | |||||
| (a) | Facility used for letters of credit and borrowings for general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount includes $141 million of commitments from Lehman that are only available from the fronting banks and the swingline lender and excludes $26 million of requested cash draws that have not been funded by Lehman. All outstanding borrowings under this facility at December 31, 2009 bear interest at LIBOR plus 3.5%, and a commitment fee is payable quarterly in arrears at a rate per annum equal to 0.50% of the average daily unused portion of the facility. |
| (b) | Facility used for issuing letters of credit for general corporate purposes, including, but not limited to, providing collateral support under hedging arrangements and other commodity transactions that are not eligible for funding under the TCEH Commodity Collateral Posting Facility. The borrowings under this facility were drawn at the inception of the facility, are classified as long-term debt, and except for $115 million related to a letter of credit drawn in June 2009, have been retained as restricted cash. Letters of credit totaling $736 million issued as of December 31, 2009 are supported by the restricted cash, and the remaining letter of credit availability totals $399 million. |
| (c) | Pursuant to PUCT rules, TCEH is required to maintain available capacity under its credit facilities to assure adequate credit worthiness of TCEH’s REP subsidiaries, including the ability to return retail customer deposits, if necessary. As a result, at December 31, 2009, the total availability under the TCEH credit facilities should be further reduced by $228 million. |
| (d) | Revolving facility used to fund cash collateral posting requirements for specified volumes of natural gas hedges totaling approximately 600 million MMBtu as of December 31, 2009. As of December 31, 2009, there were no borrowings under this facility. See “TCEH Senior Secured Facilities” below for additional information. |
| (e) | Facility used by Oncor for its general corporate purposes. Borrowings are classified as short-term borrowings. Availability amount excludes $122 million of commitments from Lehman. All outstanding borrowings under this facility at December 31, 2009 bear interest at LIBOR plus 0.350%, and a facility fee is payable (currently at a rate per annum equal to 0.125%) on the commitments under the facility. The interest rate and facility fee rate per annum declined in June 2009 from LIBOR plus 0.425% and 0.150%, respectively, due to a two notch upgrade in Oncor’s credit ratings by Moody’s. |
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Long-Term Debt
At December 31, 2009 and 2008, the long-term debt consisted of the following:
| December 31, 2009 | December 31, 2008 | |||||||
TCEH | ||||||||
Pollution Control Revenue Bonds: | ||||||||
Brazos River Authority: | ||||||||
5.400% Fixed Series 1994A due May 1, 2029 | $ | 39 | $ | 39 | ||||
7.700% Fixed Series 1999A due April 1, 2033 | 111 | 111 | ||||||
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013 (a) | 16 | 16 | ||||||
7.700% Fixed Series 1999C due March 1, 2032 | 50 | 50 | ||||||
8.250% Fixed Series 2001A due October 1, 2030 | 71 | 71 | ||||||
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011 (a) | 217 | 217 | ||||||
8.250% Fixed Series 2001D-1 due May 1, 2033 | 171 | 171 | ||||||
0.264% Floating Series 2001D-2 due May 1, 2033 (b) | 97 | 97 | ||||||
0.317% Floating Taxable Series 2001I due December 1, 2036 (c) | 62 | 62 | ||||||
0.264% Floating Series 2002A due May 1, 2037 (b) | 45 | 45 | ||||||
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013 (a) | 44 | 44 | ||||||
6.300% Fixed Series 2003B due July 1, 2032 | 39 | 39 | ||||||
6.750% Fixed Series 2003C due October 1, 2038 | 52 | 52 | ||||||
5.400% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014 (a) | 31 | 31 | ||||||
5.000% Fixed Series 2006 due March 1, 2041 | 100 | 100 | ||||||
Sabine River Authority of Texas: | ||||||||
6.450% Fixed Series 2000A due June 1, 2021 | 51 | 51 | ||||||
5.500% Fixed Series 2001A due May 1, 2022, remarketing date November 1, 2011 (a) | 91 | 91 | ||||||
5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011 (a) | 107 | 107 | ||||||
5.200% Fixed Series 2001C due May 1, 2028 | 70 | 70 | ||||||
5.800% Fixed Series 2003A due July 1, 2022 | 12 | 12 | ||||||
6.150% Fixed Series 2003B due August 1, 2022 | 45 | 45 | ||||||
Trinity River Authority of Texas: | ||||||||
6.250% Fixed Series 2000A due May 1, 2028 | 14 | 14 | ||||||
Unamortized fair value discount related to pollution control revenue bonds (d) | (147 | ) | (161 | ) | ||||
Senior Secured Facilities: | ||||||||
3.743% TCEH Initial Term Loan Facility maturing October 10, 2014 (e)(f) | 16,079 | 16,244 | ||||||
3.735% TCEH Delayed Draw Term Loan Facility maturing October 10, 2014 (e)(f) | 4,075 | 3,562 | ||||||
3.731% TCEH Letter of Credit Facility maturing October 10, 2014 (f) | 1,250 | 1,250 | ||||||
0.215% TCEH Commodity Collateral Posting Facility maturing December 31, 2012 (g) | — | — | ||||||
Other: | ||||||||
10.25% Fixed Senior Notes due November 1, 2015 (h) | 2,944 | 3,000 | ||||||
10.25% Fixed Senior Notes Series B due November 1, 2015 (h) | 1,913 | 2,000 | ||||||
10.50 / 11.25% Senior Toggle Notes due November 1, 2016 | 1,952 | 1,750 | ||||||
7.000% Fixed Senior Notes due March 15, 2013 | 5 | 5 | ||||||
7.100% Promissory Note due January 5, 2009 | — | 65 | ||||||
7.460% Fixed Secured Facility Bonds with amortizing payments through January 2015 | 55 | 67 | ||||||
Capital lease obligations | 153 | 159 | ||||||
Unamortized fair value discount (d) | (4 | ) | (6 | ) | ||||
Total TCEH | $ | 29,810 | $ | 29,470 | ||||
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| December 31, 2009 | December 31, 2008 | |||||||
EFC Holdings | ||||||||
9.580% Fixed Notes due in semiannual installments through December 4, 2019 | $ | 51 | $ | 55 | ||||
8.254% Fixed Notes due in quarterly installments through December 31, 2021 | 50 | 53 | ||||||
1.081% Floating Rate Junior Subordinated Debentures, Series D due January 30, 2037 (f) | 1 | 1 | ||||||
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037 | 8 | 8 | ||||||
Unamortized fair value discount (d) | (11 | ) | (12 | ) | ||||
Total EFC Holdings | 99 | 105 | ||||||
EFH Corp. (parent entity) | ||||||||
10.875% Fixed Senior Notes due November 1, 2017 | 1,831 | 2,000 | ||||||
11.25 / 12.00% Senior Toggle Notes due November 1, 2017 | 2,797 | 2,500 | ||||||
9.75% Fixed Senior Secured Notes due October 15, 2019 | 115 | — | ||||||
4.800% Fixed Senior Notes Series O due November 15, 2009 | — | 3 | ||||||
5.550% Fixed Senior Notes Series P due November 15, 2014 (i) | 983 | 1,000 | ||||||
6.500% Fixed Senior Notes Series Q due November 15, 2024 (i) | 740 | 750 | ||||||
6.550% Fixed Senior Notes Series R due November 15, 2034 (i) | 744 | 750 | ||||||
8.820% Building Financing due semiannually through February 11, 2022 (j) | 75 | 80 | ||||||
Unamortized fair value premium related to Building Financing (d) | 17 | 22 | ||||||
Unamortized fair value discount (d) | (599 | ) | (661 | ) | ||||
Total EFH Corp. | 6,703 | 6,444 | ||||||
Intermediate Holding | ||||||||
9.75% Fixed Senior Secured Notes due October 15, 2019 | 141 | — | ||||||
Oncor (k) | ||||||||
6.375% Fixed Senior Notes due May 1, 2012 | 700 | 700 | ||||||
5.950% Fixed Senior Notes due September 1, 2013 | 650 | 650 | ||||||
6.375% Fixed Senior Notes due January 15, 2015 | 500 | 500 | ||||||
6.800% Fixed Senior Notes due September 1, 2018 | 550 | 550 | ||||||
7.000% Fixed Debentures due September 1, 2022 | 800 | 800 | ||||||
7.000% Fixed Senior Notes due May 1, 2032 | 500 | 500 | ||||||
7.250% Fixed Senior Notes due January 15, 2033 | 350 | 350 | ||||||
7.500% Fixed Senior Notes due September 1, 2038 | 300 | 300 | ||||||
Unamortized discount | (15 | ) | (16 | ) | ||||
Total Oncor | 4,335 | 4,334 | ||||||
Oncor Electric Delivery Transition Bond Company LLC (l) | ||||||||
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010 | 13 | 54 | ||||||
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013 | 130 | 130 | ||||||
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015 | 145 | 145 | ||||||
3.520% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2009 | — | 39 | ||||||
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012 | 197 | 221 | ||||||
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016 | 290 | 290 | ||||||
Total Oncor Electric Delivery Transition Bond Company LLC | 775 | 879 | ||||||
Unamortized fair value discount related to transition bonds (d) | (6 | ) | (9 | ) | ||||
Total Oncor consolidated | 5,104 | 5,204 | ||||||
Total EFH Corp. consolidated | 41,857 | 41,223 | ||||||
Less amount due currently (m) | (417 | ) | (385 | ) | ||||
Total long-term debt | $ | 41,440 | $ | 40,838 | ||||
| (a) | These series are in the multiannual interest rate mode and are subject to mandatory tender prior to maturity on the mandatory remarketing date. On such date, the interest rate and interest rate period will be reset for the bonds. |
| (b) | Interest rates in effect at December 31, 2009. These series are in a daily interest rate mode and are classified as long-term as they are supported by long-term irrevocable letters of credit. |
| (c) | Interest rate in effect at December 31, 2009. This series is in a weekly interest rate mode and is classified as long-term as it is supported by long-term irrevocable letters of credit. |
| (d) | Amount represents unamortized fair value adjustments recorded under purchase accounting. |
| (e) | Interest rate swapped to fixed on $16.30 billion principal amount. |
| (f) | Interest rates in effect at December 31, 2009. |
| (g) | Interest rate in effect at December 31, 2009, excluding a quarterly maintenance fee of approximately $11 million. See “Credit Facilities” above for more information. |
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| (h) | 2009 amounts exclude $56 million and $87 million of the original and Series B notes, respectively, that are held by EFH Corp. and Intermediate Holding and eliminated in consolidation. See discussion of debt exchanges below. |
| (i) | 2009 amounts exclude $9 million, $6 million and $3 million of the Series P, Series Q and Series R notes, respectively, that are held by Intermediate Holding and eliminated in consolidation. See discussion of debt exchanges below. |
| (j) | This financing is secured and will be serviced with $115 million in restricted cash drawn in June 2009 by the beneficiary of a letter of credit. The issuer elected not to extend the expiration date of the letter of credit, and TCEH elected to allow the drawing in lieu of reissuing the letter of credit under the TCEH Revolving Credit Facility. The remaining $104 million of the prepayment (net of $11 million of debt service payments) is included in other current assets and other noncurrent assets on the balance sheet. |
| (k) | Secured with first priority lien as discussed under “Oncor Secured Revolving Credit Facility” below. |
| (l) | These bonds are nonrecourse to Oncor and were issued to securitize a regulatory asset. |
| (m) | Includes zero and $3 million at December 31, 2009 and 2008, respectively, representing debt of the EFH Corp. parent entity. |
EFH Corp. 10% Senior Secured Notes Issued in 2010— In January 2010, EFH Corp. issued $500 million aggregate principal amount of 10.00% Senior Secured Notes due 2020 (the EFH Corp. 10% Notes). The notes will mature on January 15, 2020, and interest is payable in cash in arrears on January 15 and July 15 of each year at a fixed rate of 10.00% per annum with the first interest payment due on July 15, 2010. Other than interest rate and maturity date, the notes have the same guarantees and collateral and substantially the same other terms and conditions as the EFH Corp. 9.75% Notes.
Before January 15, 2013, EFH Corp. may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of its EFH Corp. 10% Notes from time to time at a redemption price of 110.000% of the aggregate principal amount of the notes, plus accrued and unpaid interest, if any. EFH Corp. may redeem the notes at any time prior to January 15, 2015 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. EFH Corp. may also redeem the notes, in whole or in part, at any time on or after January 15, 2015, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control (as described in the indenture), EFH Corp. may be required to offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.
The EFH Corp. 10% Notes were issued in a private placement and have not been registered under the Securities Act. EFH Corp. has agreed to use its commercially reasonable efforts to register with the SEC notes having substantially identical terms as the EFH Corp. 10% Notes (except for provisions relating to the transfer restrictions and payment of additional interest) as part of an offer to exchange freely tradable exchange notes for the EFH Corp. 10% Notes. EFH Corp. has agreed to use commercially reasonable efforts to cause the exchange offer to be completed or, if required under special circumstances, to have one or more shelf registration statements declared effective, within 360 days after the issue date of the notes. If this obligation is not satisfied (a Registration Default), the annual interest rate on the notes will increase by 25 basis points for the first 90-day period during which a Registration Default continues, and thereafter the annual interest rate on the notes will increase by 50 basis points for the remaining period during which the Registration Default continues. If the Registration Default is cured, the interest rate on the notes will revert to the original level.
Debt-Related Activity in 2009— Repayments of long-term debt in 2009 totaling $396 million represented principal payments at scheduled maturity dates as well as other repayments totaling $50 million, principally related to capitalized leases. Payments at scheduled amortization or maturity dates included $165 million repaid under the TCEH Initial Term Loan Facility, $104 million of Oncor transition bond principal payments, $65 million repaid under a TCEH promissory note, $9 million repaid under the TCEH Delayed Draw Term Loan Facility and $3 million of EFH Corp. senior notes.
Increases in long-term debt during 2009 totaling $522 million consisted of increased borrowings under the TCEH Delayed Draw Term Loan Facility, which was fully drawn as of July 2009, to fund expenditures related to construction of new generation facilities and environmental upgrades of existing lignite/coal-fueled generation facilities. In addition, long-term debt increased as a result of EFH Corp. increasing, through the payment-in-kind (PIK) election, the principal amount of its 11.25%/12.00% Senior Toggle Notes due November 2017 (EFH Corp. Toggle Notes) by $309 million and TCEH increasing, through the PIK election, the principal amount of its 10.50%/11.25% Senior Toggle Notes due November 2016 (TCEH Toggle Notes) by $202 million, in each case, in lieu of making cash interest payments.
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Debt Exchanges — In October 2009, EFH Corp., Intermediate Holding and EFIH Finance, a wholly-owned subsidiary of Intermediate Holding, commenced offers to exchange up to approximately $4.9 billion principal amount of EFH Corp. 10.875% Senior Notes due November 2017 (EFH Corp. 10.875% Notes) and EFH Corp. Toggle Notes (collectively with the EFH Corp. 10.875% Notes, the EFH Corp. Senior Notes), EFH Corp. Series P, Q and R Notes and TCEH 10.25% Notes due November 2015 (the TCEH 10.25% Notes and collectively, with the EFH Corp. 10.875% Notes, Toggle Notes and Series P, Q and R Notes, the Old Notes) for up to $3.0 billion of new senior secured notes, with up to $1.35 billion to be issued by EFH Corp. and up to $1.65 billion to be issued by Intermediate Holding and EFIH Finance (the EFIH Co-Issuers). The purpose of the debt exchanges was to reduce the outstanding principal amount and extend the weighted average maturity of our long-term debt.
The debt exchange transactions, which closed in November 2009, resulted in the tendering of $357 million principal amount of Old Notes in exchange for $115 million principal amount of 9.75% Senior Secured Notes issued by EFH Corp. (the EFH Corp. 9.75% Notes) and $141 million principal amount of 9.75% Senior Secured Notes issued by Intermediate Holding and EFIH Finance (the EFIH Notes). The EFH Corp. 9.75% Notes and EFIH Notes will mature in October 2019, with interest payable in cash semi-annually in arrears on April 15 and October 15.
The EFH Corp. 9.75% Notes are fully and unconditionally guaranteed on a joint and several basis by EFC Holdings and Intermediate Holding. The guarantee from Intermediate Holding is secured by the pledge of all membership interests and other investments Intermediate Holding owns or holds in Oncor Holdings or any of Oncor Holdings’ subsidiaries (the Collateral). The guarantee from EFC Holdings is not secured. The EFIH Notes are secured by the Collateral on a parity lien basis with the EFH Corp. 9.75% Notes.
The EFH Corp. 9.75% Notes and EFIH Notes are senior obligations of each issuer and rank equally in right of payment with all senior indebtedness of each issuer and are senior in right of payment to any future subordinated indebtedness of each issuer. The EFH Corp. 9.75% Notes are effectively subordinated to any indebtedness of EFH Corp. secured by assets of EFH Corp. to the extent of the value of the assets securing such indebtedness and structurally subordinated to all indebtedness and other liabilities of EFH Corp.’s non-guarantor subsidiaries. The EFIH Notes are effectively senior to all unsecured indebtedness of the EFIH Co-Issuers, to the extent of the value of the Collateral, and will be effectively subordinated to any indebtedness of the EFIH Co-Issuers secured by assets of the EFIH Co-Issuers other than the Collateral, to the extent of the value of the assets securing such indebtedness. Furthermore, the EFIH Notes will be structurally subordinated to all indebtedness and other liabilities of Intermediate Holding’s subsidiaries (other than EFIH Finance), including Oncor Holdings and its subsidiaries.
The guarantees of the EFH Corp. 9.75% Notes are the general senior obligations of each guarantor and rank equally in right of payment with all existing and future senior indebtedness of each guarantor. The guarantee from Intermediate Holding is effectively senior to all unsecured indebtedness of Intermediate Holding to the extent of the value of the Collateral. The guarantee will be effectively subordinated to all secured indebtedness of each guarantor secured by assets other than the Collateral to the extent of the value of the assets securing such indebtedness and will be structurally subordinated to any existing and future indebtedness and liabilities of EFH Corp.’s subsidiaries that are not guarantors.
The EFH Corp. 9.75% Notes and EFIH Notes and indentures governing such notes restrict the issuers and their restricted subsidiaries’ ability to, among other things, make restricted payments, incur debt and issue preferred stock, incur liens, permit dividend and other payment restrictions on restricted subsidiaries, merge, consolidate or sell assets and engage in transactions with affiliates. These covenants are subject to a number of limitations and exceptions. The notes and indentures also contain customary events of default, including, among others, failure to pay principal or interest on the notes when due. If certain events of default occur and are continuing under a series of notes and the related indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes of such series may declare the principal amount of the notes of such series to be due and payable immediately.
There currently are no restricted subsidiaries under the indenture related to the EFIH Notes (other than EFIH Finance, which has no assets). Oncor Holdings, the immediate parent of Oncor, and its subsidiaries are unrestricted subsidiaries under the EFIH indenture and, accordingly, will not be subject to any of the restrictive covenants in the indenture.
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The respective issuers may redeem the EFH Corp. 9.75% Notes and EFIH Notes, in whole or in part, at any time on or after October 15, 2014, at specified redemption prices, plus accrued and unpaid interest, if any. In addition, before October 15, 2012, the respective issuers may redeem up to 35% of the aggregate principal amount of each series of the notes from time to time at a redemption price of 109.750% of the aggregate principal amount of such series of notes, plus accrued and unpaid interest, if any, with the net cash proceeds of certain equity offerings. The respective issuers may also redeem each series of the notes at any time prior to October 15, 2014 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. Upon the occurrence of a change of control (as described in the indenture), the respective issuers may be required to offer to repurchase each series of the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.
Debt-Related Activity in 2008— Repayments of long-term debt in 2008 totaling $1.167 billion represented principal payments at scheduled maturity dates as well as the remarketing of $242 million principal amount of pollution control revenue bonds discussed below, repayment of $413 million of borrowings under the TCEH Commodity Collateral Posting Facility, which fully repaid borrowings under the facility, and other repayments totaling $48 million, principally related to leases. Payments at scheduled maturity dates included $200 million of EFH Corp. senior notes, $165 million repaid under the TCEH Initial Term Loan Facility, and $99 million of Oncor transition bond principal payments.
Increases in long-term debt during 2008 totaling $3.185 billion consisted of issuances of senior secured notes issued by Oncor with an aggregate principal amount of $1.500 billion (see discussion below under “Oncor Senior Secured Notes”), borrowings under the TCEH Delayed Draw Term Loan Facility of $1.412 billion to fund expenditures related to the development of new generation facilities and the environmental retrofit program for existing lignite/coal-fueled generation facilities, the remarketing of $242 million principal amount of pollution control revenue bonds discussed immediately below and $31 million of additional borrowings under the TCEH Commodity Collateral Posting Facility.
In June 2008, TCEH remarketed the Brazos River Authority Pollution Control Revenue Bonds Series 2001A due in October 2030 and Series 2001D-1 due in May 2033 with aggregate principal amounts of $71 million and $171 million, respectively. The bonds were previously in a floating rate mode that reset weekly and were backed by two letters of credit in an aggregate amount of $247 million. As a result of the remarketing, the bonds were fixed to maturity at an interest rate of 8.25%, and the two letters of credit were cancelled. The bonds are redeemable at par beginning July 1, 2018 and are redeemable with a make-whole premium prior to July 1, 2018. These bonds were remarketed with a covenant package similar to the notes discussed below under “TCEH Senior Notes.”
Maturities — Long-term debt maturities as of December 31, 2009 are as follows (includes Oncor’s transition bond semi-annual payments):
Year | ||||
2010 | $ | 340 | ||
2011 | 764 | |||
2012 | 1,056 | |||
2013 | 1,071 | |||
2014 | 21,746 | |||
Thereafter (a) | 17,492 | |||
Unamortized fair value premium | 17 | |||
Unamortized fair value discount (b) | (767 | ) | ||
Unamortized discount | (15 | ) | ||
Capital lease obligations | 153 | |||
Total | $ | 41,857 | ||
| (a) | Long-term debt maturities for EFH Corp. (parent entity) total $7.328 billion, including $18 million held by Intermediate Holding that is not included above. |
| (b) | Unamortized fair value discount for EFH Corp. (parent entity) totals $(599) million. |
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TCEH Senior Secured Facilities — Borrowings under the TCEH Initial Term Loan Facility, the TCEH Delayed Draw Term Loan Facility, the TCEH Revolving Credit Facility and the TCEH Letter of Credit Facility, which totaled $22.357 billion at December 31, 2009, bear interest at per annum rates equal to, at TCEH’s option, (i) adjusted LIBOR plus 3.50% or (ii) a base rate (the higher of (1) the prime rate as announced from time to time by the administrative agent of the facilities and (2) the federal funds effective rate plus 0.50%) plus 2.50%. There is a margin adjustment mechanism in relation to term loans, revolving loans and letter of credit fees under which the applicable margins may be reduced based on the achievement of certain leverage ratio levels; there was no such reduction based upon December 31, 2009 levels. The applicable rate on borrowings under the facilities as of December 31, 2009 is provided in the long-term debt table and in the discussion of short-term borrowings above and reflects LIBOR-based borrowings.
In August 2009, the TCEH Senior Secured Facilities were amended to reduce the existing first lien capacity under the TCEH Senior Secured Facilities by $1.25 billion in exchange for the ability for TCEH to issue up to an additional $4 billion of secured notes or loans ranking junior to TCEH’s first lien obligations, provided that:
| • | such notes or loans mature later than the latest maturity date of any of the initial term loans under the TCEH Senior Secured Facilities, and |
| • | any net cash proceeds from any such issuances are used (i) in exchange for, or to refinance, repay, retire, refund or replace indebtedness of TCEH or (ii) to acquire, directly or indirectly, all or substantially all of the property and assets or business of another person or to finance the purchase price, cost of design, acquisition, construction, repair, restoration, replacement, expansion, installation or improvement of certain fixed or capital assets. |
In addition, the amended facilities permit TCEH to, among other things:
| • | issue new secured notes or loans, which may include, in each case, indebtedness secured on a pari passu basis with the obligations under the TCEH Senior Secured Facilities, so long as, in each case, among other things, the net cash proceeds from any such issuance are used to prepay certain loans under the TCEH Senior Secured Facilities at par; |
| • | agree with individual lenders to extend the maturity of their term loans or extend or refinance their revolving credit commitments under the TCEH Senior Secured Facilities, and pay increased interest rates or otherwise modify the terms of their loans or revolving commitments in connection with such an extension, and |
| • | exclude from the financial maintenance covenant under the TCEH Senior Secured Facilities any new debt issued that ranks junior to TCEH’s first lien obligations under the TCEH Senior Secured Facilities. |
Under the terms of the TCEH Senior Secured Facilities, the commitments of the lenders to make loans to TCEH are several and not joint. Accordingly, if any lender fails to make loans to TCEH, TCEH’s available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the TCEH Senior Secured Facilities.
The TCEH Senior Secured Facilities are unconditionally guaranteed jointly and severally on a senior secured basis by EFC Holdings, and subject to certain exceptions, each existing and future direct or indirect wholly-owned US restricted subsidiary of TCEH. The TCEH Senior Secured Facilities, including the guarantees thereof, certain commodity hedging transactions and the interest rate swaps described under “TCEH Interest Rate Swap Transactions” below are secured by (a) substantially all of the current and future assets of TCEH and TCEH’s subsidiaries who are guarantors of such facilities and (b) pledges of the capital stock of TCEH and certain current and future direct or indirect subsidiaries of TCEH.
The TCEH Initial Term Loan Facility is required to be repaid in equal quarterly installments in an aggregate annual amount equal to 1% of the original principal amount of such facility (approximately $41 million quarterly), with the balance payable in October 2014. The TCEH Delayed Draw Term Loan Facility is required to be repaid in equal quarterly installments beginning in December 2009 in an aggregate annual amount equal to 1% of the actual principal outstanding under such facility as of such date, with the balance payable in October 2014. Amounts borrowed under the TCEH Revolving Facility may be reborrowed from time to time until October 2013. The TCEH Letter of Credit Facility and TCEH Commodity Collateral Posting Facility will mature in October 2014 and December 2012, respectively.
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The TCEH Senior Secured Facilities contain customary negative covenants, restricting, subject to certain exceptions, TCEH and TCEH’s restricted subsidiaries from, among other things:
| • | incurring additional debt; |
| • | incurring additional liens; |
| • | entering into mergers and consolidations; |
| • | selling or otherwise disposing of assets; |
| • | making dividends, redemptions or other distributions in respect of capital stock; |
| • | making acquisitions, investments, loans and advances, and |
| • | paying or modifying certain subordinated and other material debt. |
In addition, the TCEH Senior Secured Facilities contain a maintenance covenant that prohibits TCEH and its restricted subsidiaries from exceeding a maximum consolidated secured leverage ratio and to observe certain customary reporting requirements and other affirmative covenants.
The TCEH Senior Secured Facilities contain certain customary events of default for senior leveraged acquisition financings, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments.
TCEH Senior Notes— The indebtedness under TCEH’s and TCEH Finance’s 10.25% Senior Notes due November 1, 2015 and 10.25% Senior Notes due November 1, 2015 (Series B) (collectively, TCEH 10.25% Notes) bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.25% per annum payable in cash. The indebtedness under the TCEH Toggle Notes bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.50% per annum for cash interest and at a fixed rate of 11.25% per annum for PIK interest. For any interest periods until November 2012, the issuers may elect to pay interest on the notes (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new TCEH Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. TCEH made the PIK election for both interest payments in 2009, increasing the principal amount. Once TCEH makes a PIK election, the election is valid for each succeeding interest payment period until TCEH revokes the election.
The TCEH 10.25% and Toggle Notes (collectively, the TCEH Senior Notes) are fully and unconditionally guaranteed on a joint and several basis by TCEH’s direct parent, EFC Holdings (which owns 100% of TCEH and its subsidiary guarantors), and by each subsidiary that guarantees the TCEH Senior Secured Facilities.
Before November 1, 2010, the issuers may redeem with the cash proceeds of certain equity offerings up to 35% of the aggregate principal amount of the TCEH 10.25% and Toggle Notes from time to time at a redemption price of 110.250% and 110.500%, respectively, of their respective aggregate principal amount plus accrued and unpaid interest, if any. The issuers may also redeem the TCEH Senior Notes at any time prior to November 1, 2011 and 2012, respectively, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and the applicable premium as defined in the indenture. The issuers may redeem the TCEH Senior Notes, in whole or in part, at any time on or after November 1, 2011 and 2012, respectively, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFC Holdings or TCEH, the issuers may be required to offer to repurchase the TCEH Senior Notes at 101% of their principal amount, plus accrued and unpaid interest, if any.
The indenture for the TCEH Senior Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, the Co-Issuers’ and their restricted subsidiaries’ ability to:
| • | make restricted payments; |
| • | incur debt and issue preferred stock; |
| • | create liens; |
| • | enter into mergers or consolidations; |
| • | sell or otherwise dispose of certain assets; |
| • | permit dividend and other payment restrictions on restricted subsidiaries, and |
| • | engage in certain transactions with affiliates. |
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The indenture also contains customary events of default, including failure to pay principal or interest on the notes when due, among others. If certain events of default occur and are continuing under the indenture, the trustee or the holders of at least 30% in principal amount of the notes may declare the principal amount on the notes to be due and payable immediately.
EFH Corp. Senior Notes — Borrowings under EFH Corp.’s 10.875% Notes bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 10.875% per annum payable in cash. Borrowings under EFH Corp.’s 11.250%/12.000% Senior Toggle Notes due November 1, 2017 bear interest semiannually in arrears on May 1 and November 1 of each year at a fixed rate of 11.250% per annum for cash interest and at a fixed rate of 12.000% per annum for PIK Interest. For any interest period until November 1, 2012, EFH Corp. may elect to pay interest on the notes, at EFH Corp.’s option (i) entirely in cash; (ii) by increasing the principal amount of the notes or by issuing new EFH Corp. Toggle Notes (PIK Interest); or (iii) 50% in cash and 50% in PIK Interest. EFH Corp. made the PIK election for both interest payments in 2009, increasing the principal amount of the EFH Corp. Toggle Notes. Once EFH Corp. makes a PIK election, the election is valid for each succeeding interest payment period until EFH Corp. revokes the election.
The EFH Corp. Senior Notes are fully and unconditionally guaranteed on a joint and several basis by EFC Holdings and Intermediate Holding.
Before November 1, 2010, EFH Corp. may redeem, with the net cash proceeds of certain equity offerings, up to 35% of the aggregate principal amount of its 10.875% and Toggle Notes from time to time at a redemption price of 110.875% and 111.250%, respectively, of their respective aggregate principal amounts, plus accrued and unpaid interest, if any. EFH Corp. may redeem the notes at any time prior to November 1, 2012 at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. EFH Corp. may also redeem the notes, in whole or in part, at any time on or after November 1, 2012, at specified redemption prices, plus accrued and unpaid interest, if any. Upon the occurrence of a change of control of EFH Corp., EFH Corp. must offer to repurchase the notes at 101% of their principal amount, plus accrued and unpaid interest, if any.
The indenture for the EFH Corp. Senior Notes contains a number of covenants that, among other things, restrict, subject to certain exceptions, EFH Corp.’s and its restricted subsidiaries’ ability to:
| • | make restricted payments; |
| • | incur debt and issue preferred stock; |
| • | create liens; |
| • | enter into mergers or consolidations; |
| • | sell or otherwise dispose of certain assets; |
| • | permit dividend and other payment restrictions on restricted subsidiaries, and |
| • | engage in certain transactions with affiliates. |
The indenture also contains customary events of default, including failure to pay principal or interest on the notes or the guarantees when due, among others. If an event of default occurs under the indenture, the trustee or the holders of at least 30% in principal amount outstanding of the notes may declare the principal amount on the notes to be due and payable immediately.
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Intercreditor Agreement — In October 2007, TCEH entered into an intercreditor agreement with Citibank, N.A. and five secured commodity hedge counterparties (the Secured Commodity Hedge Counterparties). In connection with the August 2009 amendment to the TCEH Secured Facilities described above, the intercreditor agreement was amended and restated (as amended and restated, the “Intercreditor Agreement”) to take into account, among other things, the possibility that TCEH could issue notes and/or loans secured by collateral (other than the collateral that secures the TCEH Senior Secured Facilities) that ranks on parity with, or junior to, TCEH’s existing first lien obligations under the TCEH Senior Secured Facilities. The Intercreditor Agreement provides that the lien granted to the Secured Commodity Hedge Counterparties will rank pari passu with the lien granted with respect to the collateral of the secured parties under the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will be entitled to share, on a pro rata basis, in the proceeds of any liquidation of such collateral in connection with a foreclosure on such collateral in an amount provided in the TCEH Senior Secured Facilities. The Intercreditor Agreement also provides that the Secured Commodity Hedge Counterparties will have voting rights with respect to any amendment or waiver of any provision of the Intercreditor Agreement that changes the priority of the Secured Commodity Hedge Counterparties’ lien on such collateral relative to the priority of lien granted to the secured parties under the TCEH Senior Secured Facilities or the priority of payments to the Secured Commodity Hedge Counterparties upon a foreclosure and liquidation of such collateral relative to the priority of the lien granted to the secured parties under the TCEH Senior Secured Facilities.
TCEH Interest Rate Swap Transactions— As of December 31, 2009, TCEH has entered into interest rate swap transactions pursuant to which payment of the floating interest rates on an aggregate of $16.30 billion of senior secured term loans of TCEH were exchanged for interest payments at fixed rates of between 7.3% and 8.3% on debt maturing from 2010 to 2014. Swaps on $1.25 billion principal amount of senior secured debt expired in 2009. Interest rate swaps on an aggregate of $15.05 billion were being accounted for as cash flow hedges related to variable interest rate cash flows until August 29, 2008, at which time these swaps were dedesignated as cash flow hedges as a result of the intent to change the variable interest rate terms of the hedged debt (from three-month LIBOR to one-month LIBOR) in connection with the planned execution of interest rate basis swaps (discussed immediately below) to further reduce the fixed borrowing costs. Based on the fair value of the positions, the cumulative unrealized mark-to-market net losses related to these interest rate swaps totaled $431 million (pre-tax) at the dedesignation date and was recorded in accumulated other comprehensive income. This balance will be reclassified into net income as interest on the hedged debt is reflected in net income. No ineffectiveness gains or losses were recorded.
As of December 31, 2009, TCEH has entered into interest rate basis swap transactions pursuant to which payments at floating interest rates of three-month LIBOR on an aggregate of $16.25 billion principal amount of senior secured term loans of TCEH were exchanged for floating interest rates of one-month LIBOR plus spreads ranging from 0.0625% to 0.353%. These transactions include swaps entered into in the year ended December 31, 2009 related to an aggregate $9.55 billion principal amount of senior secured term loans of TCEH and reflect the expiration of swaps in the year ended December 31, 2009 that related to an aggregate $6.345 billion principal amount of senior secured term loans of TCEH.
The interest rate swap counterparties are proportionately secured by the same collateral package granted to the lenders under the TCEH Senior Secured Facilities. Subsequent to the dedesignation in August 2008 discussed above, changes in the fair value of such swaps are being reported in the income statement in interest expense and related charges, and such unrealized mark-to-market value changes totaled $696 million in net gains in the year ended December 31, 2009 and $1.477 billion in net losses in the year ended December 31, 2008. The cumulative unrealized mark-to-market net liability related to the swaps totaled $1.212 billion at December 31, 2009, of which $194 million (pre-tax) was reported in accumulated other comprehensive income.
See Note 18 for discussion of collateral investments related to certain of these interest rate swaps.
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Oncor Secured Revolving Credit Facility— Oncor has a $2.0 billion credit facility to be used for its working capital and general corporate purposes, including issuances of commercial paper and letters of credit (Oncor Revolving Credit Facility). Oncor may request increases in the commitments under the facility in any amount up to $500 million, subject to the satisfaction of certain conditions. Amounts borrowed under the facility, once repaid, can be reborrowed by Oncor from time to time until October 10, 2013. Under the terms of this credit facility, the commitments of the lenders to make loans to Oncor are several and not joint. Accordingly, if any lender fails to make loans to Oncor, Oncor’s available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the Oncor Revolving Credit Facility. Oncor secured this credit facility with a first priority lien on certain of its transmission and distribution assets. Oncor also secured all of its existing long-term debt securities (excluding the transition bonds) with the same lien in accordance with the terms of those securities. The lien contains customary provisions allowing Oncor to use the assets in its business, as well as to replace and/or release collateral as long as the market value of the aggregate collateral is at least 115% of the aggregate secured debt. The lien may be terminated at Oncor’s option upon the termination of Oncor’s credit facility. Borrowings under this credit facility totaled $616 million and $337 million at December 31, 2009 and 2008, respectively. The applicable rate on borrowings under this credit facility as of December 31, 2009 was 0.58% (see detail provided in the credit facilities table above).
The credit facility contains customary covenants for facilities of this type, restricting, subject to certain exceptions, Oncor and its subsidiary from, among other things:
| • | incurring additional liens; |
| • | entering into mergers and consolidations; |
| • | selling certain assets, and |
| • | making acquisitions and investments in subsidiaries. |
In addition, the credit facility requires that Oncor maintain a consolidated senior debt-to-capitalization ratio of no greater than 0.65 to 1.00 and observe certain customary reporting requirements and other affirmative covenants.
The credit facility contains certain customary events of default for facilities of this type, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments under the facility.
Oncor Senior Secured Notes— In September 2008, Oncor issued and sold senior secured notes with an aggregate principal amount of $1.500 billion consisting of $650 million aggregate principal amount of 5.95% senior secured notes maturing in September 2013, $550 million aggregate principal amount of 6.80% senior secured notes maturing in September 2018 and $300 million aggregate principal amount of 7.50% senior secured notes maturing in September 2038. Oncor used the net proceeds of approximately $1.487 billion from the sale of the Oncor notes to repay most of its borrowings under its credit facility as well as for general corporate purposes. The Oncor notes are secured by the first priority lien described above. If the lien is terminated, the notes will cease to be secured obligations of Oncor and will become senior unsecured general obligations of Oncor.
Interest on these notes is payable in cash semiannually in arrears on March 1 and September 1 of each year. Oncor may redeem the notes, in whole or in part, at any time, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. The notes also contain customary events of default, including failure to pay principal or interest on the notes when due.
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| 13. | COMMITMENTS AND CONTINGENCIES |
Contractual Commitments
At December 31, 2009, we had noncancellable commitments under energy-related contracts, leases and other agreements as follows:
| Coal purchase agreements and coal transportation agreements | Pipeline transportation and storage reservation fees | Capacity payments under power purchase agreements (a) | Nuclear Fuel Contracts | Water Rights Contracts | |||||||||||
2010 | $ | 425 | $ | 38 | $ | 38 | $ | 158 | $ | 10 | |||||
2011 | 404 | 36 | — | 127 | 9 | ||||||||||
2012 | 292 | 23 | — | 182 | 9 | ||||||||||
2013 | 259 | — | — | 119 | 8 | ||||||||||
2014 | 253 | — | — | 102 | 8 | ||||||||||
Thereafter | — | — | — | 480 | 37 | ||||||||||
Total | $ | 1,633 | $ | 97 | $ | 38 | $ | 1,168 | $ | 81 | |||||
| (a) | On the basis of current expectations of demand from electricity customers as compared with capacity and take-or-pay payments, management does not consider it likely that any material payments will become due for electricity not taken beyond capacity payments. |
At December 31, 2009, future minimum lease payments under both capital leases and operating leases are as follows:
| Capital Leases | Operating Leases (a) | |||||
2010 | $ | 81 | $ | 65 | ||
2011 | 17 | 59 | ||||
2012 | 17 | 56 | ||||
2013 | 12 | 49 | ||||
2014 | 7 | 46 | ||||
Thereafter | 43 | 286 | ||||
Total future minimum lease payments | 177 | $ | 561 | |||
Less amounts representing interest | 24 | |||||
Present value of future minimum lease payments | 153 | |||||
Less current portion | 76 | |||||
Long-term capital lease obligation | $ | 77 | ||||
| ||||||
| (a) | Includes operating leases with initial or remaining noncancellable lease terms in excess of one year. |
In February 2010, a capital lease related to a mining railroad spur was terminated, and we purchased the related spur for $63 million. At December 31, 2009, the balance of the capital lease liability was $63 million. The assets were recorded at cost as property, plant and equipment and will be depreciated over their remaining useful lives, the weighted average of which is 23 years.
Rent reported as operating costs, fuel costs and SG&A expenses totaled $92 million for both years ended December 31, 2009 and 2008, $26 million for the period October 11, 2007 through December 31, 2007 and $66 million for the Predecessor period January 1, 2007 through October 10, 2007.
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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. 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.
Capital Expenditures
Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As one of the provisions of this stipulation, Oncor committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. See Note 6.
Guarantees
We have entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions. Material guarantees are discussed below.
Disposed TXU Gas operations —In connection with the sale of TXU Gas in October 2004, EFH Corp. agreed to indemnify Atmos Energy Corporation (Atmos), until October 1, 2014, for up to $500 million for any liability related to assets retained by TXU Gas, including certain inactive gas plant sites not acquired by Atmos, and up to $1.4 billion for contingent liabilities associated with preclosing tax and employee related matters. The maximum aggregate amount under these indemnities that we may be required to pay is $1.9 billion. To date, we have not been required to make any payments to Atmos under any of these indemnity obligations, and no such payments are currently anticipated.
Residual value guarantees in operating leases — We are the lessee under various operating leases that guarantee the residual values of the leased assets. At December 31, 2009, the aggregate maximum amount of residual values guaranteed was approximately $45 million with an estimated residual recovery of approximately $49 million. These leased assets consist primarily of mining equipment, rail cars and vehicles. The average life of the residual value guarantees under the lease portfolio is approximately four years.
See Note 12 for discussion of guarantees and security for certain of our indebtedness.
Letters of Credit
At December 31, 2009, TCEH had outstanding letters of credit under its credit facilities totaling $736 million as follows:
| • | $379 million to support risk management and trading margin requirements in the normal course of business, including over-the-counter hedging transactions; |
| • | $208 million to support floating rate pollution control revenue bond debt with an aggregate principal amount of $204 million (the letters of credit are available to fund the payment of such debt obligations and expire in 2014); |
| • | $65 million for collateral funding transactions with counterparties to interest rate swap agreements related to TCEH debt (see Note 18), and |
| • | $84 million for miscellaneous credit support requirements. |
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Litigation Related to Generation Facilities
In September 2007, an administrative appeal challenging the order of the TCEQ issuing the air permit for construction and operation of the Oak Grove generation facility in Robertson County, Texas was filed in the State District Court of Travis County, Texas. Plaintiffs asked that the District Court reverse the TCEQ’s approval of the Oak Grove air permit and the TCEQ’s adoption and approval of the TCEQ Executive Director’s Response to Comments, and remand the matter back to TCEQ for further proceedings. In addition to this administrative appeal, two other petitions were filed in Travis County District Court by non-parties to the administrative hearing before the TCEQ and the State Office of Administrative Hearings (SOAH) seeking to challenge the TCEQ’s issuance of the Oak Grove air permit and asking the District Court to remand the matter to the SOAH for further proceedings. Finally, the plaintiffs in these two additional lawsuits filed a third, joint petition claiming insufficiencies in the Oak Grove application, permit, and process and seeking party status and remand to the SOAH for further proceedings. One of the plaintiffs asked the District Court to consolidate all these proceedings, and the Attorney General of Texas, on behalf of TCEQ, filed pleas to the jurisdiction seeking dismissal of all but the administrative appeal. In May 2009, the District Court dismissed the claims that contest the merits of the TCEQ’s permitting decision, but declined to dismiss the claims that contest the process by which the TCEQ handled the permit application. Oak Grove Management Company LLC (a subsidiary of TCEH) has subsequently intervened in these proceedings and has filed its own pleas to the jurisdiction asking the court to dismiss the remaining collateral attack claims. In October 2009, one of the plaintiffs ended its legal challenge to the permit. In December 2009, the Attorney General and Oak Grove Management Company LLC filed pleadings asking the court to dismiss the administrative appeal challenging the permit for want of prosecution by the plaintiffs. In January 2010, the court denied that request and set the case for a hearing on the merits on June 16, 2010. We believe the Oak Grove air permit granted by the TCEQ was issued in accordance with applicable law. There can be no assurance that the outcome of these matters will not adversely impact the Oak Grove project.
In June and September 2008, administrative appeals were filed in the State District Court of Travis County, Texas to challenge the administrative action of the TCEQ Executive Director in issuing an air permit alteration for the previously-permitted construction and operation of the Sandow 5 generation facility in Milam County, Texas, and the failure of the TCEQ to overturn that administrative action. Plaintiffs asked that the District Court reverse the issuance of the permit alteration. The Attorney General of Texas, on behalf of TCEQ, is defending the issuance of the permit alteration. Sandow Power (a subsidiary of TCEH) intervened in support of the TCEQ. The District Court issued its ruling in November 2009 upholding the TCEQ’s issuance of the permit alteration. The plaintiffs did not appeal the court’s order by the deadline for such appeal. Thus, the matter has concluded favorably for EFH Corp.
In February 2010, the Sierra Club informed Luminant that it may sue Luminant, after the expiration of a 60-day waiting period, for allegedly violating federal Clean Air Act provisions in connection with Luminant’s Big Brown generation facility. This notice is similar to the notice that Luminant received in July 2008 with respect to its Martin Lake generation facility. We cannot predict whether the Sierra Club will actually file suit or the outcome of any resulting proceedings.
In July 2008, Alcoa Inc. filed a lawsuit in the State District Court of Milam County, Texas against Luminant Generation and Luminant Mining (wholly-owned subsidiaries of TCEH), later adding EFH Corp., a number of its subsidiaries, Texas Holdings and Texas Energy Future Capital Holdings LLC as parties to the suit. The lawsuit makes various claims concerning the operation of the Sandow Unit 4 generation facility and the Three Oaks lignite mine, including claims for breach of contract, breach of fiduciary duty, fraud, tortious interference, civil conspiracy and conversion. The plaintiff requests money damages of no less than $500 million, declaratory judgment, rescission and other forms of equitable relief. An agreed scheduling order is currently in place setting trial for May 2010. While we are unable to estimate any possible loss or predict the outcome of this litigation, we believe the plaintiff’s claims made in this litigation are without merit and, accordingly, intend to vigorously defend this litigation.
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Regulatory Investigations and Reviews
In June 2008, the EPA issued a request for information to TCEH under EPA’s authority under Section 114 of the Clean Air Act. The stated purpose of the request is to obtain information necessary to determine compliance with the Clean Air Act, including New Source Review Standards and air permits issued by the TCEQ for the Big Brown, Monticello and Martin Lake generation facilities. Historically, as the EPA has pursued its New Source Review enforcement initiative, companies that have received a large and broad request under Section 114, such as the request received by TCEH, have in many instances subsequently received a notice of violation from the EPA, which has in some cases progressed to litigation or settlement. The company is cooperating with the EPA and is responding in good faith to the EPA’s request, but is unable to predict the outcome of this matter.
Other Proceedings
In addition to the above, we are involved in various other legal and administrative proceedings in the normal course of business, the ultimate resolution of which, in the opinion of management, should not have a material effect on our financial position, results of operations or cash flows.
Labor Contracts
Certain personnel engaged in TCEH and Oncor activities are represented by labor unions and covered by collective bargaining agreements with varying expiration dates. In October 2009, new one-year labor agreements were reached covering bargaining unit personnel engaged in the lignite-fueled generation operations, the lignite mining operations and natural gas-fueled generation operations. In August 2008, a new labor agreement effective until August 2010 was reached covering bargaining unit personnel engaged in nuclear generation. In February 2008, a new three-year contract was ratified covering bargaining unit personnel engaged in Oncor’s operations. In June 2009, a group of approximately 50 Oncor employees voted to decertify the labor union as their representative. In December 2009, a group of approximately 350 Oncor employees elected to be represented by a labor union. We expect that any changes in collective bargaining agreements will not have a material effect on our financial position, results of operations or cash flows; however, we are unable to predict the ultimate outcome of these labor negotiations.
Environmental Contingencies
The federal Clean Air Act, as amended (Clean Air Act) includes provisions which, among other things, place limits on SO2 and NOx emissions produced by electricity generation plants. The capital requirements of the company have not been significantly affected by the requirements of the Clean Air Act. In addition, all air pollution control provisions of the 1999 Restructuring Legislation have been satisfied.
We must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. We believe that we are in compliance with current environmental laws and regulations; however, the impact, if any, of changes to existing regulations or the implementation of new regulations is not determinable.
The costs to comply with environmental regulations can be significantly affected by the following external events or conditions:
| • | enactment of state or federal regulations regarding CO2 and other greenhouse gas emissions; |
| • | other changes to existing state or federal regulation regarding air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters, including revisions to CAIR currently being developed by the EPA as a result of court rulings discussed in Note 3, and |
| • | the identification of sites requiring clean-up or the filing of other complaints in which we may be asserted to be potential responsible parties. |
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Nuclear Insurance
Nuclear insurance includes liability coverage, property damage, decontamination and premature decommissioning coverage and accidental outage and/or extra expense coverage. The liability coverage is governed by the Price-Anderson Act (Act), while the property damage, decontamination and premature decommissioning coverage are promulgated by the rules and regulations of the NRC. We intend to maintain insurance against nuclear risks as long as such insurance is available. The company is self-insured to the extent that losses (i) are within the policy deductibles, (ii) are not covered per policy exclusions, terms and limitations, (iii) exceed the amount of insurance maintained, or (iv) are not covered due to lack of insurance availability. Such losses could have a material adverse effect on our financial condition and results of operations and cash flows.
With regard to liability coverage, the Act provides financial protection for the public in the event of a significant nuclear generation plant incident. The Act sets the statutory limit of public liability for a single nuclear incident at $12.5 billion and requires nuclear generation plant operators to provide financial protection for this amount. The US Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $12.5 billion limit for a single incident mandated by the Act. As required, the company provides this financial protection for a nuclear incident at Comanche Peak resulting in public bodily injury and property damage through a combination of private insurance and industry-wide retrospective payment plans. As the first layer of financial protection, the company has $375 million of liability insurance from American Nuclear Insurers (ANI), which provides such insurance on behalf of a major stock insurance company pool, Nuclear Energy Liability Insurance Association. The second layer of financial protection is provided under an industry-wide retrospective payment program called Secondary Financial Protection (SFP).
Under the SFP, in the event of an incident at any nuclear generation plant in the US, each operating licensed reactor in the US is subject to an assessment of up to $117.5 million plus a 3% insurance premium tax, subject to increases for inflation every five years. Assessments are limited to $17.5 million per operating licensed reactor per year per incident. The company’s maximum potential assessment under the industry retrospective plan would be $235 million (excluding taxes) per incident but no more than $35 million in any one year for each incident. The potential assessment is triggered by a nuclear liability loss in excess of $375 million per accident at any nuclear facility. The SFP and liability coverage are not subject to any deductibles.
With respect to nuclear decontamination and property damage insurance, the NRC requires that nuclear generation plant license-holders maintain at least $1.06 billion of such insurance and require the proceeds thereof to be used to place a plant in a safe and stable condition, to decontaminate it pursuant to a plan submitted to and approved by the NRC before the proceeds can be used for plant repair or restoration or to provide for premature decommissioning. The company maintains nuclear decontamination and property damage insurance for Comanche Peak in the amount of $2.25 billion (subject to $5 million deductible per accident), above which the company is self-insured. This insurance coverage consists of a primary layer of coverage of $500 million provided by Nuclear Electric Insurance Limited (NEIL), a nuclear electric utility industry mutual insurance company and $1.75 billion of premature decommissioning coverage also provided by NEIL.
The company maintains Accidental Outage Insurance through NEIL to cover the additional costs of obtaining replacement electricity from another source if one or both of the units at Comanche Peak are out of service for more than twelve weeks as a result of covered direct physical damage. The coverage provides for weekly payments of $3.5 million for the first fifty-two weeks and $2.8 million for the next 110 weeks for each outage, respectively, after the initial twelve-week waiting period. The total maximum coverage is $490 million per unit. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident.
If NEIL’s losses exceeded its reserves for the applicable coverage, potential assessments in the form of a retrospective premium call could be made up to ten times annual premiums. The company maintains insurance coverage against these potential retrospective premium calls.
Also, under the NEIL policies, if there were multiple terrorism losses occurring within a one-year time frame, NEIL would make available one industry aggregate limit of $3.2 billion plus any amounts it recovers from other sources up to the limits for each claimant. If terrorism losses occurred beyond the one-year period, a new set of limits and resources would apply.
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| 14. | SHAREHOLDERS’ EQUITY |
Successor
Equity Contributions, Issuances and Repurchases—In connection with the Merger, Texas Holdings made an aggregate cash equity contribution of approximately $8.3 billion to EFH Corp. in exchange for EFH Corp. issuing approximately 1.658 billion shares of its common stock to Texas Holdings. In the year ended December 31, 2008 and the period from October 11, 2007 to December 31, 2007, EFH Corp. issued an aggregate of approximately 5.5 million and 2.0 million shares of its common stock, respectively, to, or for the benefit of, certain of its officers, directors and employees for an aggregate consideration of $27.4 million and $9.8 million, respectively. The 2008 amounts include shares previously subscribed. In addition, in the years ended December 31, 2009 and 2008, EFH Corp. issued an aggregate of 1.5 million and 1.7 million shares, respectively, of its common stock to, or for the benefit of, certain officers, directors and employees as stock-based compensation as discussed in Note 22. In 2008, EFH Corp. repurchased 0.8 million shares of its common stock from employees primarily upon termination of employment or amendment of agreements, for an aggregate consideration of $3.9 million.
Effect of Sale of Noncontrolling Interests — The total amount of proceeds from the sale of noncontrolling interests in Oncor discussed in Note 15 was less than the carrying value of the interests sold by $265 million, which reflects the fact that Oncor’s carrying value after purchase accounting is based on the Merger value, while the noncontrolling interests sale value does not include a control premium. This difference was accounted for as a reduction of shareholders’ equity.
During the preparation of our December 31, 2009 financial statements, we determined that deferred income taxes related to EFH Corp.’s interest in Oncor should have been recorded upon the sale of noncontrolling interests in November 2008. Accordingly, the December 31, 2008 balance of noncurrent accumulated deferred income tax liabilities has been increased by $141 million (from the $5.926 billion previously reported) and shareholders’ equity at that date has been decreased by the same amount (from the $3.532 billion deficit previously reported). The recognition of the deferred tax liability is the result of applying rules for income tax accounting related to outside basis differences. This error did not affect net income or cash flows previously reported.
Dividend Restrictions— The indentures governing the EFH Corp. Senior Notes, 9.75% Notes, and 10% Notes include covenants that, among other things and subject to certain exceptions, restrict our ability to pay dividends or make other distributions in respect of our capital stock. Accordingly, essentially all of our net income is restricted from being used to make distributions on our common stock unless such distributions are expressly permitted under these indentures and/or after such distributions, on a pro forma basis, after giving effect to such payment, EFH Corp.’s consolidated leverage ratio is equal to or less than 7.0 to 1.0. For purposes of this calculation, “consolidated leverage ratio” is defined as the ratio of consolidated total indebtedness (as defined in the indenture) to Adjusted EBITDA, in each case, consolidated with its subsidiaries other than Oncor Holdings and its subsidiaries. In addition, the indenture governing the EFIH Notes generally restricts Intermediate Holding from making any distribution to EFH Corp. for the ultimate purpose of making a distribution to Texas Holdings unless at the time, and after giving effect to such distribution, Intermediate Holding’s consolidated leverage ratio is equal to or less than 6.0 to 1.0. Under the indenture governing the EFIH Notes, the term “consolidated leverage ratio” is defined as the ratio of consolidated total indebtedness (as defined in the indenture) to Adjusted EBITDA on a consolidated basis.
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The TCEH Senior Secured Facilities generally restrict TCEH from making any distribution to any of its parent companies for the ultimate purpose of making a distribution to Texas Holdings unless at the time, and after giving effect to such distribution, its consolidated total debt (as defined in the TCEH Senior Secured Facilities) to Adjusted EBITDA would be equal to or less than 6.5 to 1.0. In addition, the TCEH Senior Secured Facilities and indenture governing the TCEH Senior Notes generally restrict TCEH’s ability to make distributions or loans to any of its parent companies, EFC Holdings and EFH Corp., unless such distributions or loans are expressly permitted under the TCEH Senior Secured Facilities and indenture governing the TCEH Senior Notes. Those agreements generally permit TCEH to make unlimited distributions or loans to its parent companies for corporate overhead costs, SG&A expenses, taxes and principal and interest payments. In addition, those agreements contain certain investment and dividend baskets that would allow TCEH to make additional distributions and/or loans to its parent companies up to the amount of such baskets. At December 31, 2009, EFH Corp. notes payable to TCEH totaled $1.406 billion.
In addition, under applicable law, we would be prohibited from paying any dividend to the extent that immediately following payment of such dividend, there would be no statutory surplus or we would be insolvent.
EFH Corp. has not paid any cash dividends subsequent to the Merger.
Shareholder Actions — In May 2009, the shareholders of EFH Corp. approved the change of the stated capital of EFH Corp.’s common stock, no par value per share, to an amount equal to $0.001 for each outstanding share of common stock, resulting in total stated value of outstanding common stock of $2 million. Also in May 2009, EFH Corp.’s board of directors approved a decrease in additional paid-in capital of the same amount and the allocation of $0.001 per share to stated value of common stock upon issuance of any authorized but unissued shares of common stock that may occur from time to time, with the remainder of any amounts received for such shares allocated to additional paid-in capital.
Common Stock Registration Rights— The Sponsor Group and certain other investors entered into a registration rights agreement with EFH Corp. upon closing of the Merger. Pursuant to this agreement, in certain instances, the Sponsor Group can cause EFH Corp. to register shares of EFH Corp.’s common stock owned directly or indirectly by them under the Securities Act. In certain instances, the Sponsor Group and certain other investors are also entitled to participate on a pro rata basis in any registration of EFH Corp.’s common stock under the Securities Act that it may undertake.
See Note 22 for discussion of stock-based compensation plans.
Predecessor
Declaration of Dividend— At its August 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 per share, which was paid October 1, 2007 to shareholders of record on September 7, 2007. At its May 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 per share, which was paid on July 2, 2007 to shareholders of record on June 1, 2007. At its February 2007 meeting, EFH Corp.’s board of directors declared a quarterly dividend of $0.4325 a share, payable April 2, 2007 to shareholders of record on March 2, 2007.
Thrift Plan— The Thrift Plan is an employee savings plan under which we matched a portion of employees’ contributions of their earnings with a contribution in shares of EFH Corp. common stock. Contributions to the Thrift Plan are held by an unconsolidated trust. At October 10, 2007, the Thrift Plan had an obligation of $201 million outstanding in the form of a note payable to EFH Corp. (LESOP note). Proceeds from the issuance of the note, which EFH Corp. purchased from a third-party lender in 1990, were used by the Thrift Plan trustee to purchase EFH Corp.’s common stock on the open market for the purpose of satisfying future matching requirements. These shares (LESOP shares) were held by the Thrift Plan trustee under the leveraged employee stock ownership provision of the Thrift Plan. The note receivable had been classified as a reduction of common stock equity, and the principal and related interest was being amortized as a component of LESOP-related expense.
The Thrift Plan used dividends received on the LESOP shares held and contributions from us, if required, to repay interest and principal on the LESOP note; such contributions totaled $14 million for the period from January 1, 2007 through October 10, 2007.
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On the date of the Merger, the Thrift Plan trustee held approximately 5.7 million shares of EFH Corp.’s common stock. These shares were converted to cash at $69.25 per share in connection with the closing of the Merger. The Thrift Plan trustee used the cash proceeds to repay the LESOP note, and then made an additional allocation of the remaining cash proceeds to eligible Thrift Plan participants.
The table below reflects the changes in the number of Predecessor common stock shares outstanding:
| Period from January 1, 2007 through October 10, 2007 | |||
Balance at beginning of period | 459,244,523 | ||
Issuances under stock-based incentive compensation plans (Note 22) | 2,771,257 | ||
Issued on conversion of convertible senior notes | 36,372 | ||
Forfeitures and cancellations under stock-based incentive compensation plans | (900,143 | ) | |
Purchased in connection with Merger | (461,152,009 | ) | |
Balance at end of period | — | ||
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| 15. | NONCONTROLLING INTERESTS |
In November 2008, equity interests in Oncor were sold to Texas Transmission for $1.254 billion in cash. Equity interests were also indirectly sold to certain members of Oncor’s board of directors and its management team. Accordingly, after giving effect to all equity issuances, as of December 31, 2009, Oncor’s ownership was as follows: 80.03% held indirectly by EFH Corp., 0.22% held indirectly by Oncor’s management and board of directors and 19.75% held by Texas Transmission.
The proceeds (net of closing costs) of $1.253 billion received by Oncor from Texas Transmission and the members of Oncor management upon completion of these transactions were distributed ultimately to EFH Corp. Under the terms of certain financing arrangements of EFH Corp. and TCEH, upon such distribution, under certain circumstances, EFH Corp. (parent entity) is required to repay certain outstanding intercompany loans from TCEH. In November 2008, EFH Corp. repaid the $253 million balance of notes payable to TCEH that related to payments of principal and interest on EFH Corp. (parent entity) debt.
See Note 14 for discussion of amounts recorded as a reduction of shareholders’ equity as a result of the sale of Oncor interests.
Of the noncontrolling interests balance reported in the December 31, 2009 and 2008 consolidated balance sheets, $1.363 billion and $1.355 billion, respectively, related to Oncor’s noncontrolling interests. The noncontrolling interests balance reported in the December 31, 2009 consolidated balance sheet represented the proportional share of Oncor’s net assets at the date of the transaction less $96 million representing the noncontrolling interests’ share of Oncor’s net losses for the periods subsequent to the transaction (including the goodwill impairment charge), net of $58 million in cash distributions.
In connection with the filing of a combined operating license application with the NRC for two new nuclear generation units, in January 2009, TCEH and Mitsubishi Heavy Industries Ltd. (MHI) formed a joint venture, known as Comanche Peak Nuclear Power Company LLC, to further the development of the two new nuclear generation units using MHI’s US–Advanced Pressurized Water Reactor technology. Under the terms of the joint venture agreement, a subsidiary of TCEH owns an 88% interest in the venture and a subsidiary of MHI owns a 12% interest. This joint venture is a variable interest entity, and a subsidiary of TCEH is considered the primary beneficiary.
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| 16. | FAIR VALUE MEASUREMENTS |
Accounting standards related to the determination of fair value define fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. We use a “mid-market” valuation convention (the mid-point price between bid and ask prices) as a practical expedient to measure fair value for the majority of our assets and liabilities subject to fair value measurement on a recurring basis. We primarily use the market approach for recurring fair value measurements and use valuation techniques to maximize the use of observable inputs and minimize the use of unobservable inputs.
We categorize our assets and liabilities recorded at fair value based upon the following fair value hierarchy:
| • | Level 1 valuations use quoted prices in active markets for identical assets or liabilities that are accessible at the measurement date. An active market is a market in which transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 assets and liabilities include exchange traded commodity contracts. For example, a significant number of our derivatives are NYMEX futures and swaps transacted through clearing brokers for which prices are actively quoted. |
| • | Level 2 valuations use inputs, in the absence of actively quoted market prices, that are observable for the asset or liability, either directly or indirectly. Level 2 inputs include: (a) quoted prices for similar assets or liabilities in active markets, (b) quoted prices for identical or similar assets or liabilities in markets that are not active, (c) inputs other than quoted prices that are observable for the asset or liability such as interest rates and yield curves observable at commonly quoted intervals and (d) inputs that are derived principally from or corroborated by observable market data by correlation or other means. Our Level 2 valuations utilize over-the-counter broker quotes, quoted prices for similar assets or liabilities that are corroborated by correlations or other mathematical means and other valuation inputs. For example, our Level 2 assets and liabilities include forward commodity positions at locations for which over-the-counter broker quotes are available. |
| • | Level 3 valuations use unobservable inputs for the asset or liability. Unobservable inputs are used to the extent observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date. We use the most meaningful information available from the market combined with internally developed valuation methodologies to develop our best estimate of fair value. For example, our Level 3 assets and liabilities include certain derivatives whose values are derived from pricing models that utilize multiple inputs to the valuations, including inputs that are not observable or easily corroborated through other means. |
We utilize several different valuation techniques to measure the fair value of assets and liabilities, relying primarily on the market approach of using prices and other market information for identical and/or comparable assets and liabilities for those items that are measured on a recurring basis. These methods include, among others, the use of broker quotes and statistical relationships between different price curves.
In utilizing broker quotes, we attempt to obtain multiple quotes from brokers that are active in the commodity markets in which we participate (and require at least one quote from two brokers to determine a pricing input as observable); however, not all pricing inputs are quoted by brokers. The number of broker quotes received for certain pricing inputs varies depending on the depth of the trading market, each individual broker’s publication policy, recent trading volume trends and various other factors. In addition, for valuation of interest rate swaps, we use a combination of dealer provided market valuations (generally non-binding) and Bloomberg valuations based on month-end interest rate curves and standard rate swap valuation models.
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Certain derivatives and financial instruments are valued utilizing option pricing models that take into consideration multiple inputs including commodity prices, volatility factors, discount rates and other inputs. Additionally, when there is not a sufficient amount of observable market data, valuation models are developed that incorporate proprietary views of market factors. Those valuation models are generally used in developing long-term forward price curves for certain commodities. We believe the development of such curves is consistent with industry practice; however, the fair value measurements resulting from such curves are classified as Level 3.
With respect to amounts presented in the following fair value hierarchy tables, the fair value measurement of an asset or liability (e.g., a contract) is required to fall in its entirety in one level, based on the lowest level input that is significant to the fair value measurement. Certain assets and liabilities would be classified in Level 2 instead of Level 3 of the hierarchy except for the effects of credit reserves and non-performance risk adjustments, respectively. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability being measured.
At December 31, 2009, assets and liabilities measured at fair value on a recurring basis consisted of the following:
| Level 1 | Level 2 | Level 3 (a) | Reclassification(b) | Total | |||||||||||
Assets: | |||||||||||||||
Commodity contracts | $ | 918 | $ | 2,588 | $ | 350 | $ | 4 | $ | 3,860 | |||||
Interest rate swaps | — | 64 | — | — | 64 | ||||||||||
Nuclear decommissioning trust – equity securities (c) | 154 | 105 | — | — | 259 | ||||||||||
Nuclear decommissioning trust – debt securities (c) | — | 216 | — | — | 216 | ||||||||||
Total assets | $ | 1,072 | $ | 2,973 | $ | 350 | $ | 4 | $ | 4,399 | |||||
Liabilities: | |||||||||||||||
Commodity contracts | $ | 1,077 | $ | 796 | $ | 269 | $ | 4 | $ | 2,146 | |||||
Interest rate swaps | — | 1,306 | — | — | 1,306 | ||||||||||
Total liabilities | $ | 1,077 | $ | 2,102 | $ | 269 | $ | 4 | $ | 3,452 | |||||
| |||||||||||||||
| (a) | Level 3 assets and liabilities consist primarily of complex long-term power purchase and sales agreements, including long-term wind generation purchase contracts and certain natural gas positions (collars) in the long-term hedging program. |
| (b) | Represents the effects of reclassification of the assets and liabilities to conform to the balance sheet presentation of current and long-term assets and liabilities. |
| (c) | The nuclear decommissioning trust investment is included in the Investments line on the balance sheet. See Note 19. |
See Note 21 for fair value measurements related to pension and OPEB plan assets.
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At December 31, 2008, assets and liabilities measured at fair value on a recurring basis consisted of the following:
| Level 1 | Level 2 | Level 3 (a) | Total | |||||||||
Assets: | ||||||||||||
Commodity contracts | $ | 1,010 | $ | 2,061 | $ | 283 | $ | 3,354 | ||||
Interest rate swaps | — | 142 | — | 142 | ||||||||
Nuclear decommissioning trust – equity securities (b) | 109 | 83 | — | 192 | ||||||||
Nuclear decommissioning trust – debt securities (b) | — | 193 | — | 193 | ||||||||
Total assets | $ | 1,119 | $ | 2,479 | $ | 283 | $ | 3,881 | ||||
Liabilities: | ||||||||||||
Commodity contracts | $ | 1,288 | $ | 1,274 | $ | 355 | $ | 2,917 | ||||
Interest rate swaps | — | 2,086 | — | 2,086 | ||||||||
Total liabilities | $ | 1,288 | $ | 3,360 | $ | 355 | $ | 5,003 | ||||
| ||||||||||||
| (a) | Level 3 assets and liabilities consist primarily of complex long-term power purchase and sales agreements, including long-term wind generation purchase contracts and certain natural gas positions (collars) in the long-term hedging program. |
| (b) | The nuclear decommissioning trust investment is included in the Investments line on the balance sheet. See Note 19. |
Commodity contracts consist primarily of natural gas, electricity, fuel oil and coal derivative instruments entered into for hedging purposes and include physical contracts that have not been designated “normal” purchases or sales. See Note 18 for further discussion regarding the company’s use of derivative instruments.
Interest rate swaps include variable-to-fixed rate swap instruments that are economic hedges of interest on long-term debt as well as interest rate basis swaps designed to effectively reduce the hedged borrowing costs. See Note 12 for discussion of interest rate swaps.
Nuclear decommissioning trust assets represent securities held for the purpose of funding the future retirement and decommissioning of the nuclear generation units. These investments include equity, debt and other fixed-income securities consistent with investment rules established by the NRC and the PUCT.
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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, 2009 and 2008:
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | |||||||
Balance at beginning of period | $ | (72 | ) | $ | (173 | ) | ||
Total realized and unrealized gains (losses) (a): | ||||||||
Included in net income (loss) | 115 | (5 | ) | |||||
Included in other comprehensive income (loss) | (30 | ) | — | |||||
Purchases, sales, issuances and settlements (net) (b) | 51 | (13 | ) | |||||
Net transfers in and/or out of Level 3 (c) | 17 | 119 | ||||||
Balance at end of period | $ | 81 | $ | (72 | ) | |||
Net change in unrealized gains (losses) included in net income relating to instruments held at end of period (d) | $ | 105 | 87 | |||||
| ||||||||
| (a) | Substantially all changes in values of commodity contracts are reported in the income statement in net gain (loss) from commodity hedging and trading activities. |
| (b) | Settlements represent reversals of unrealized mark-to-market valuations of these positions previously recognized in net income. Purchases and issuances reflect option premiums paid or received. |
| (c) | Includes transfers due to changes in the observability of significant inputs used in valuing derivatives. Transfers in are assumed to transfer in at the beginning of the quarter and transfers out at the end of the quarter, which is when the assessments are performed. Any changes in value during the period are reported as unrealized gains and losses in net gain (loss) from commodity hedging and trading activities. |
| (d) | Includes unrealized gains and losses of instruments held at the end of the period. |
| 17. | FAIR VALUE OF NONDERIVATIVE FINANCIAL INSTRUMENTS |
The carrying amounts and related estimated fair values of significant nonderivative financial instruments were as follows:
| Successor | ||||||||||||||||
| December 31, 2009 | December 31, 2008 | |||||||||||||||
| Carrying Amount | Fair Value (a) | Carrying Amount | Fair Value (a) | |||||||||||||
On balance sheet assets (liabilities): | ||||||||||||||||
Long-term debt (including current maturities) (b): | ||||||||||||||||
TCEH, EFH Corp., and other | $ | (36,600 | ) | $ | (29,115 | ) | $ | (35,860 | ) | $ | (24,162 | ) | ||||
Oncor | $ | (5,104 | ) | $ | (5,644 | ) | $ | (5,204 | ) | $ | (4,990 | ) | ||||
Total | $ | (41,704 | ) | $ | (34,759 | ) | $ | (41,064 | ) | $ | (29,152 | ) | ||||
Off balance sheet assets (liabilities): | ||||||||||||||||
Financial guarantees | $ | — | $ | (6 | ) | $ | — | $ | (3 | ) | ||||||
| ||||||||||||||||
| (a) | Fair value determined in accordance with accounting standards related to the determination of fair value. |
| (b) | Excludes capital leases. |
See Notes 16 and 18 for discussion of accounting for financial instruments that are derivatives.
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| 18. | COMMODITY AND OTHER DERIVATIVE CONTRACTUAL ASSETS AND LIABILITIES |
Risk Management Hedging Strategy
We enter into physical and financial derivative instruments, such as options, swaps, futures and forward contracts, primarily to manage commodity price risk and interest rate risk exposure. Our principal activities involving derivatives consist of a long-term hedging program and the hedging of interest costs on our long-term debt. See Note 16 for a discussion of the fair value of all derivatives.
Long-Term Hedging Program —TCEH has a long-term hedging program designed to reduce exposure to changes in future electricity prices due to changes in the price of natural gas, thereby hedging future revenues from electricity sales and related cash flows. In ERCOT, the wholesale price of electricity is highly correlated to the price of natural gas. Under the program, TCEH has entered into market transactions involving natural gas-related financial instruments and has sold forward natural gas over the next five years. These transactions are intended to hedge a majority of electricity price exposure related to expected baseload generation for this period. Changes in the fair value of the instruments under the long-term hedging program are reported in the income statement in net gain (loss) from commodity hedging and trading activities.
Interest Rate Swap Transactions — Interest rate swap agreements are used to reduce exposure to interest rate changes by converting floating-rate debt to a fixed basis, thereby hedging future interest costs and related cash flows. Interest rate basis swaps are used to effectively reduce the hedged borrowing costs. Changes in the fair value of the swaps are recorded as unrealized gains and losses in interest expense and related charges. See Note 12 for additional information about these and other interest rate swap agreements.
Other Commodity Hedging and Trading Activity —In addition to the long-term hedging program, TCEH enters into derivatives, including electricity, natural gas, fuel oil and coal instruments, generally for shorter-term hedging purposes. To a limited extent, TCEH also enters into derivative transactions for proprietary trading purposes, principally in natural gas and electricity markets.
The following table provides detail of commodity and other derivative contractual assets and liabilities, substantially all arising from mark-to-market accounting, as reported in the balance sheet at December 31, 2009:
| Derivatives not under hedge accounting | ||||||||||||||||||
| 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, 2009, there were no derivative positions accounted for as cash flow or fair value hedges.
Margin deposits that contractually offset these derivative instruments are reported separately in the balance sheet and totaled $358 million and $190 million in net liabilities at December 31, 2009 and 2008, respectively, which do not include the collateral investments related to certain interest rate swaps and commodity positions discussed immediately below. Reported amounts as presented in the above table do not reflect netting of assets and liabilities with the same counterparties under existing netting arrangements. This presentation can result in significant volatility in derivative assets and liabilities because we may enter into offsetting positions with the same counterparties, resulting in both assets and liabilities, and the underlying commodity prices can change significantly from period to period.
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In early 2009, we entered into collateral funding transactions with counterparties to certain interest rate swap agreements related to TCEH debt. Under the terms of these transactions, which we elected to enter into as a cash management measure, as of December 31, 2009, EFH Corp. (parent) has posted $400 million in cash and TCEH has posted $65 million in letters of credit to the counterparties, with the outstanding balance of such collateral earning interest. TCEH had also entered into commodity hedging transactions with one of these counterparties, and under an arrangement effective August 2009, both the interest rate swaps and certain of the commodity hedging transactions with the counterparty are under the same derivative agreement, which continues to be secured by a first-lien interest in the assets of TCEH. We are not required to post any additional collateral to these counterparties, regardless of the net mark-to-market liability under the applicable derivative agreement, and the applicable counterparty will return the cash collateral to the extent the mark-to-market liability under the applicable derivative agreement falls below the funded amount, subject to a $50 million minimum transfer amount. At December 31, 2009, the collateral posted approximated the net mark-to-market liability of the related derivatives. Under the agreements, the counterparties are to return any remaining collateral, along with accrued and unpaid interest, on March 31, 2010. The cash collateral was recorded as an investment and is presented in the balance sheet (including accrued interest) as a separate line item under current assets.
The following table presents the pre-tax effect of derivatives not under hedge accounting on net income, including realized and unrealized effects:
Derivative (Income statement presentation) | Year Ended December 31, 2009 | ||
Commodity contracts (Net gain (loss) from commodity hedging and trading activities) | $ | 1,741 | |
Interest rate swaps (Interest expense and related charges) | 12 | ||
Net gain | $ | 1,753 | |
Amounts reported in the income statement in net gain (loss) from commodity hedging and trading activities include net “day one” mark-to-market losses of $2 million, $68 million and $8 million in the 2009, 2008 and 2007 Successor periods, respectively, and $201 million in the 2007 Predecessor period. Substantially all of these losses arose from a related series of derivative transactions entered into under the long-term hedging program. The 2007 Predecessor period amount is net of a $30 million “day one” gain associated with a long-term power purchase agreement.
A multi-year power sales agreement was entered into with Alcoa Inc. in the 2007 Predecessor period. The agreement was determined to be a derivative and resulted in a “day one” mark-to-market loss of $235 million. The agreement was entered into concurrently with the transfer of an air permit from Alcoa Inc. to a subsidiary of ours as well as other agreements with Alcoa Inc. that provide, among other things, access to real property and a supply of lignite fuel, all of which provides value to us by providing the right and ability to develop, construct and operate the new lignite-fueled generation unit at Sandow. In consideration of this right and ability, the initial “day one” loss of the sales agreement, as well as a $29 million below market value of a related interim power sales agreement entered into in late 2006, were recorded as part of the construction work-in-process asset balance for the Sandow unit.
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The following tables present the pre-tax effect of derivative instruments accounted for as cash flow hedges on net income (loss) and other comprehensive income (loss) (OCI) for the year ended December 31, 2009:
Derivative | Amount of (loss) recognized in OCI (effective portion) | Income statement presentation of gain (loss) reclassified from accumulated | Amount | |||||||
Interest rate swaps | $ | — | Interest expense and related charges | $ | (184 | ) | ||||
Commodity contracts | (30 | ) | Fuel, purchased power costs and delivery fees | (16 | ) | |||||
| Operating revenues | (2 | ) | ||||||||
Total | $ | (30 | ) | $ | (202 | ) | ||||
There were no ineffectiveness net gains or losses related to transactions designated as cash flow hedges in the year ended December 31, 2009.
Accumulated other comprehensive income related to cash flow hedges at December 31, 2009 totaled $128 million in net losses (after-tax), substantially all of which relates to interest rate swaps. We expect that $59 million of net losses related to cash flow hedges included in accumulated other comprehensive income as of December 31, 2009 will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.
Derivative Volumes— The following table presents the gross notional amounts of derivative volumes at December 31, 2009:
Derivative type | Notional Volume | Unit of Measure | |||
Interest rate swaps: | |||||
Floating/fixed | $ | 18,000 | Million US dollars | ||
Basis | $ | 16,250 | Million US dollars | ||
Natural gas: | |||||
Long-term hedge forward sales and purchases (a) | 3,402 | Million MMBtu | |||
Locational basis swaps | 1,010 | Million MMBtu | |||
All other | 1,433 | Million MMBtu | |||
Electricity | 198,230 | GWh | |||
Coal | 6 | Million tons | |||
Fuel oil | 161 | Million gallons | |||
| |||||
| (a) | Represents gross notional forward sales, purchases and options of fixed and basis (price point) transactions in the long-term hedging program. The net amount of these transactions, excluding basis transactions, is 1.6 billion MMBtu. |
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Credit Risk-Related Contingent Features
The agreements that govern our derivative instrument transactions may contain certain credit risk-related contingent features that could trigger liquidity requirements in the form of cash collateral, letters of credit or some other form of credit enhancement. Certain of those agreements require the posting of collateral if our credit rating is downgraded by one or more of the credit rating agencies; however, due to our below investment grade ratings, substantially all of such collateral posting requirements are already effective.
As of December 31, 2009, the fair value of liabilities related to derivative instruments under agreements with credit risk-related contingent features that were not fully cash collateralized totaled $687 million. The liquidity exposure associated with these liabilities was reduced by cash and letter of credit postings with the counterparties totaling $152 million as of December 31, 2009. If all the credit risk-related contingent features related to these derivatives had been triggered, including cross default provisions, as of December 31, 2009, the remaining related liquidity requirement would have totaled $20 million after reduction for net accounts receivable and derivative assets under netting arrangements.
In addition, certain derivative agreements that are collateralized primarily with asset liens include indebtedness cross-default provisions that could result in the settlement of such contracts if there were a failure under other financing arrangements to meet payment terms or to comply with other covenants that could result in the acceleration of such indebtedness. As of December 31, 2009, the fair value of derivative liabilities subject to such cross-default provisions, largely related to interest rate swaps, totaled $1.482 billion (before consideration of the amount of assets under the liens). The liquidity exposure associated with these liabilities was reduced by cash collateral and letters of credit posted with counterparties totaling $489 million as of December 31, 2009. If all the credit risk-related contingent features related to these derivatives, including amounts related to cross-default provisions, had been triggered as of December 31, 2009, the remaining related liquidity requirement would have totaled $480 million after reduction for derivative assets under netting arrangements (before consideration of the amount of assets under the liens). See Note 12 for a description of other obligations that are supported by asset liens.
As discussed immediately above, the aggregate fair values of liabilities under derivative agreements with credit risk-related contingent features, including cross-default provisions, totaled $2.169 billion at December 31, 2009. This amount is before consideration of cash and letter of credit collateral posted, net accounts receivable and derivative assets under netting arrangements and assets under related liens.
Some commodity derivative contracts contain credit risk-related contingent features that do not provide for specific amounts to be posted if the features are triggered. These provisions include material adverse change, performance assurance, and other clauses that generally provide counterparties with the right to request additional credit enhancements. The amounts disclosed above exclude credit risk-related contingent features that do not provide for specific amounts or exposure calculations.
Concentrations of Credit Risk
TCEH has significant concentrations of credit risk with the counterparties to its derivative contracts. As of December 31, 2009, total credit risk exposure to all counterparties related to derivative contracts totaled $4.0 billion. The net exposure to those counterparties totaled $1.3 billion after taking into effect master netting arrangements, setoff provisions and collateral. As of December 31, 2009, the credit risk exposure to the banking and financial sector represented more than 90% of the total credit risk exposure. As of December 31, 2009, the largest net exposure to a single counterparty totaled $536 million. Exposure to the banking and financial sector counterparties is considered to be within an acceptable level of risk tolerance because substantially all of this exposure is with counterparties with credit ratings of “A” or better. However, this concentration increases the risk that a default by any of these counterparties would have a material adverse effect on our financial condition and results of operations.
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The transactions with these counterparties contain certain provisions that would require the counterparties to post collateral in the event of a material downgrade in their credit rating. We maintain credit risk policies with regard to our counterparties to minimize overall credit risk. These policies specify authorized risk mitigation tools including, but not limited to, use of standardized master netting contracts and agreements that allow for netting of positive and negative exposures associated with a single counterparty. Credit enhancements such as parent guarantees, letters of credit, surety bonds, liens on assets and margin deposits are also utilized. Prospective material adverse changes in the payment history or financial condition of a counterparty or downgrade of its credit quality result in the reassessment of the credit limit with that counterparty. The process can result in the subsequent reduction of the credit limit or a request for additional financial assurances. An event of default by one or more counterparties could subsequently result in termination-related settlement payments that reduce available liquidity if amounts are owed to the counterparties related to the commodity contracts or delays in receipts of expected settlements if the counterparties owe amounts to us.
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| 19. | INVESTMENTS |
The investments balance consists of the following:
| December 31, | December 31, | |||||
| 2009 | 2008 | |||||
Nuclear decommissioning trust | $ | 475 | $ | 385 | ||
Assets related to employee benefit plans, including employee savings programs, net of distributions | 184 | 210 | ||||
Land | 43 | 44 | ||||
Investment in natural gas gathering pipeline business (a) | 44 | — | ||||
Miscellaneous other | 4 | 6 | ||||
Total investments | $ | 750 | $ | 645 | ||
| ||||||
| (a) | A controlling interest in this previously consolidated subsidiary was sold in August 2009. |
Nuclear Decommissioning Trust
Investments in a trust that will be used to fund the costs to decommission the Comanche Peak nuclear generation plant are carried at fair value. Decommissioning costs are being recovered from Oncor’s customers as a delivery fee surcharge over the life of the plant and deposited in the trust fund. Net gains and losses on investments in the trust fund are offset by a corresponding adjustment to a regulatory asset/liability. A summary of investments in the fund follows:
| December 31, 2009 | |||||||||||||
| Cost (a) | Unrealized gain | Unrealized loss | Fair market value | ||||||||||
Debt securities (b) | $ | 211 | $ | 8 | $ | (3 | ) | $ | 216 | ||||
Equity securities (c) | 195 | 83 | (19 | ) | 259 | ||||||||
Total | $ | 406 | $ | 91 | $ | (22 | ) | $ | 475 | ||||
| December 31, 2008 | |||||||||||||
| Cost (a) | Unrealized gain | Unrealized loss | Fair market value | ||||||||||
Debt securities (b) | $ | 203 | $ | 4 | $ | (14 | ) | $ | 193 | ||||
Equity securities (c) | 181 | 46 | (35 | ) | 192 | ||||||||
Total | $ | 384 | $ | 50 | $ | (49 | ) | $ | 385 | ||||
| |||||||||||||
| (a) | Includes realized gains and losses of securities sold. |
| (b) | The investment objective for debt securities is to invest in a diversified tax efficient portfolio with an overall portfolio rating of AA or above as graded by S&P or Aa2 by Moody’s. The debt securities are heavily weighted with municipal bonds. The debt securities had an average coupon rate of 4.44% and 3.77% and an average maturity of 7.8 years and 8.0 years at December 31, 2009 and 2008, respectively. |
| (c) | The investment objective for equity securities is to invest tax efficiently and to match the performance of the S&P 500 Index. |
Debt securities held at December 31, 2009 mature as follows: $82 million in one to five years, $32 million in five to ten years and $102 million after ten years.
Assets Related to Employee Benefit Plans
The majority of these assets represent cash surrender values of life insurance policies that are purchased to fund liabilities under deferred compensation plans. We pay the premiums and are the beneficiary of these life insurance policies. As of December 31, 2009 and 2008, the face amount of these policies totaled $322 million and $481 million, and the net cash surrender values totaled $124 million and $155 million, respectively. Changes in cash surrender value are netted against premiums paid. Other investment assets held to satisfy deferred compensation liabilities are recorded at fair value.
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| 20. | TERMINATION OF OUTSOURCING ARRANGEMENTS |
In connection with the closing of the Merger, EFH Corp., TCEH and Oncor commenced a review, under the change of control provision, of certain outsourcing arrangements with Capgemini, Capgemini America, Inc. and Capgemini North America, Inc. (collectively, CgE). In 2008, EFH Corp. and TCEH executed a Separation Agreement with CgE. Simultaneous with the execution of that Separation Agreement, Oncor entered into a substantially similar Separation Agreement with CgE. The Separation Agreements principally provide for (i) notice of termination of each of the Master Framework Agreements, dated as of May 17, 2004, as each has been amended, between Capgemini and each of TCEH and Oncor and the related service agreements under each of the Master Framework Agreements and (ii) termination of the joint venture arrangements between EFH Corp. (and its applicable subsidiaries) and CgE. Under the Master Framework Agreements and related services agreements, Capgemini provided outsourced support services, including information technology, customer care and billing, human resources, procurement and certain finance and accounting activities. As a result, during 2008:
| • | the 2.9% limited partnership interest in Capgemini owned by a subsidiary of EFH Corp. was redeemed in exchange for the termination of the license that was granted by a subsidiary of EFH Corp. to Capgemini at the time the Master Framework Agreements were executed in order for Capgemini to use certain information technology assets primarily consisting of capitalized software to provide services to us and third parties; |
| • | we received approximately $70 million in exchange for the termination of a purchase option agreement pursuant to which our subsidiaries had the right to “put” to Capgemini (and Capgemini had the right to “call” from a subsidiary of ours) our 2.9% limited partnership interest in Capgemini and the licensed assets upon the expiration of the Master Framework Agreements in 2014 or, in some circumstances, earlier, and |
| • | Capgemini repaid $25 million (plus accrued interest) representing all amounts owed by Capgemini under the working capital loan provided by us in July 2004. |
Under the Separation Agreements, the parties also entered into a mutual release of all claims under the Master Framework Agreements and related services agreements and the joint venture agreements, subject to certain defined exceptions, resulting in our receipt of $10 million in cash settlement.
The carrying value of the partnership interest was $2.9 million, and the carrying value of the purchase option was $177 million prior to the application of purchase accounting (recorded as a noncurrent asset). The effects of the termination of the outsourcing arrangements, including an accrued liability of $54 million for incremental costs to exit and transition the services, were included in the final purchase price allocation. See Note 2 for additional disclosure, including a reversal to income of a portion of the liability recorded in purchase accounting.
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| 21. | PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS |
EFH Corp. is the plan sponsor of the EFH Retirement Plan (Retirement Plan), which provides benefits to eligible employees of subsidiaries (participating employers). The Retirement Plan is a qualified defined benefit pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of ERISA. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. The interest component of the Cash Balance Formula is variable and is determined using the yield on 30-year Treasury bonds. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs.
Effective October 1, 2007, all new employees, with the exception of employees hired by Oncor, are not eligible to participate in the Retirement Plan. New hires at Oncor are eligible to participate in the Cash Balance Formula of the Retirement Plan. It is our policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations.
We also have supplemental unfunded retirement plans for certain employees whose retirement benefits cannot fully be earned under the qualified Retirement Plan, the information for which is included below.
We offer OPEB in the form of health care and life insurance to eligible employees and their eligible dependents upon the retirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree’s age and years of service.
Regulatory Recovery of Pension and OPEB Costs
PURA provides for the recovery by Oncor of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility, which in addition to Oncor’s own employees consists largely of active and retired personnel engaged in TCEH’s activities, related to service of those additional personnel prior to the deregulation and disaggregation of our businesses effective January 1, 2002. Oncor is authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Amounts deferred are ultimately subject to regulatory approval. As of December 31, 2009, Oncor had recorded regulatory assets totaling $889 million related to pension and OPEB costs, including amounts related to deferred expenses as well as amounts related to unfunded liabilities that otherwise would be recorded as other comprehensive income.
Pension and OPEB Costs Recognized as Expense
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Pension costs | $ | 44 | $ | 21 | $ | (1 | ) | $ | 34 | |||||||||
OPEB costs | 70 | 58 | 11 | 49 | ||||||||||||||
Total benefit costs | 114 | 79 | 10 | 83 | ||||||||||||||
Less amounts deferred principally as a regulatory asset or property | (66 | ) | (42 | ) | (8 | ) | (43 | ) | ||||||||||
Net amounts recognized as expense | $ | 48 | $ | 37 | $ | 2 | $ | 40 | ||||||||||
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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, 2009, 2008, 2007 and October 10, 2007 measurement dates:
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Assumptions Used to Determine Net Periodic Pension Cost: | ||||||||||||||||||
Discount rate | 6.90 | % | 6.55 | % | 6.45 | % | 5.90 | % | ||||||||||
Expected return on plan assets | 8.25 | % | 8.25 | % | 8.75 | % | 8.75 | % | ||||||||||
Rate of compensation increase | 3.75 | % | 3.70 | % | 3.44 | % | 3.44 | % | ||||||||||
Components of Net Pension Cost: | ||||||||||||||||||
Service cost | $ | 38 | $ | 36 | $ | 10 | $ | 30 | ||||||||||
Interest cost | 159 | 148 | 36 | 107 | ||||||||||||||
Expected return on assets | (166 | ) | (165 | ) | (47 | ) | (119 | ) | ||||||||||
Amortization of prior service cost | 1 | 1 | — | 1 | ||||||||||||||
Amortization of net loss | 12 | 1 | — | 15 | ||||||||||||||
Recognized curtailment loss | — | — | — | — | ||||||||||||||
Net periodic pension cost | $ | 44 | $ | 21 | $ | (1 | ) | $ | 34 | |||||||||
Other Changes in Plan Assets and Benefit ObligationsRecognized in Other Comprehensive Income: | ||||||||||||||||||
Net loss (gain) | $ | 45 | $ | 204 | $ | 20 | $ | (52 | ) | |||||||||
Transition obligation (asset) | — | — | — | — | ||||||||||||||
Prior service cost (credit) | — | — | — | — | ||||||||||||||
Amortization of net loss (gain) | — | — | — | (3 | ) | |||||||||||||
Amortization of transition obligation (asset) | — | — | — | — | ||||||||||||||
Amortization of prior service cost | — | — | — | (1 | ) | |||||||||||||
Reclassification to regulatory asset | — | (6 | ) | |||||||||||||||
Purchase accounting adjustment | — | (10 | ) | — | 49 | |||||||||||||
Total recognized in other comprehensive income | $ | 45 | $ | 188 | $ | 20 | $ | (7 | ) | |||||||||
Total recognized in net periodic benefit cost and other comprehensive income | $ | 89 | $ | 209 | $ | 19 | $ | 27 | ||||||||||
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||
Assumptions Used to Determine Benefit Obligations: | ||||||||||||||
Discount rate | 5.90 | % | 6.90 | % | 6.55 | % | 6.45 | % | ||||||
Rate of compensation increase | 3.71 | % | 3.75 | % | 3.70 | % | 3.44 | % | ||||||
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| Successor | ||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | |||||||
Change in Pension Obligation: | ||||||||
Projected benefit obligation at beginning of year | $ | 2,337 | $ | 2,335 | ||||
Service cost | 38 | 36 | ||||||
Interest cost | 160 | 148 | ||||||
Plan amendments | — | — | ||||||
Actuarial (gain) loss | 326 | (58 | ) | |||||
Benefits paid | (133 | ) | (124 | ) | ||||
Settlements | 14 | — | ||||||
Projected benefit obligation at end of year | $ | 2,742 | $ | 2,337 | ||||
Accumulated benefit obligation at end of year | $ | 2,581 | $ | 2,203 | ||||
Change in Plan Assets: | ||||||||
Fair value of assets at beginning of year | $ | 1,736 | $ | 2,108 | ||||
Actual return (loss) on assets | 292 | (412 | ) | |||||
Employer contributions (a) | 109 | 164 | ||||||
Benefits paid | (133 | ) | (124 | ) | ||||
Settlements | — | — | ||||||
Fair value of assets at end of year | $ | 2,004 | $ | 1,736 | ||||
Funded Status: | ||||||||
Projected pension benefit obligation | $ | (2,742 | ) | $ | (2,337 | ) | ||
Fair value of assets | 2,004 | 1,736 | ||||||
Funded status at end of year | $ | (738 | ) | $ | (601 | ) | ||
| Successor | ||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | |||||||
Amounts Recognized in the Balance Sheet Consist of: | ||||||||
Other noncurrent assets (b) | $ | 10 | $ | 10 | ||||
Other current liabilities | (4 | ) | (4 | ) | ||||
Other noncurrent liabilities | (744 | ) | (607 | ) | ||||
Net liability recognized | $ | (738 | ) | $ | (601 | ) | ||
Amounts Recognized in Accumulated Other ComprehensiveIncome Consist of: | ||||||||
Net loss | $ | 252 | $ | 208 | ||||
Prior service cost | — | — | ||||||
Net amount recognized | $ | 252 | $ | 208 | ||||
Amounts Recognized as Regulatory Assets Consist of: | ||||||||
Net loss | $ | 529 | $ | 387 | ||||
Prior service cost | 1 | 1 | ||||||
Net amount recognized | $ | 530 | $ | 388 | ||||
| (a) | 2009 amount includes transfers of investments related to the salary deferral and supplemental retirement plans totaling $31 million. |
| (b) | Amounts represent overfunded plans. |
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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.
| Successor | ||||||
| December 31, 2009 | December 31, 2008 | |||||
Pension Plans with PBO and ABO in Excess Of Plan Assets: | ||||||
Projected benefit obligations | $ | 2,738 | $ | 2,332 | ||
Accumulated benefit obligation | 2,577 | 2,199 | ||||
Plan assets | 1,989 | 1,721 | ||||
Pension Plan Investment Strategy and Asset Allocations
Our investment objective for the Retirement Plan is to invest in a suitable mix of assets to meet the future benefit obligations at an acceptable level of risk, while minimizing the volatility of contributions. Equity securities are held to achieve returns in excess of passive indexes by participating in a wide range of investment opportunities. International equity securities are used to further diversify the equity portfolio and may include investments in both developed and emerging international markets. Fixed income securities include primarily corporate bonds from a diversified range of companies, US Treasuries and agency securities and money market instruments. Our investment strategy for fixed income investments is to maintain a high grade portfolio of securities which assist us in managing the volatility and magnitude of plan contributions and expense.
The target asset allocation ranges of pension plan investments by asset category are as follows:
Asset Category | Target Allocation Ranges | |
US equities | 15%-50% | |
International equities | 5%-20% | |
Fixed income (a) | 40%-70% | |
Other | 0%-10% |
Fair Value Measurement of Pension Plan Assets
At December 31, 2009, pension plan assets measured at fair value on a recurring basis (see Note 16) consisted of the following:
Asset Category | Level 1 | Level 2 | Level 3 | Total | ||||||||
Interest-bearing cash | $ | — | $ | 99 | $ | — | $ | 99 | ||||
Equity securities: | ||||||||||||
US | 340 | 242 | — | 582 | ||||||||
International | 257 | 79 | — | 336 | ||||||||
Fixed income securities: | ||||||||||||
Corporate bonds (a) | — | 908 | — | 908 | ||||||||
US Treasuries | — | 21 | — | 21 | ||||||||
Other (b) | — | 44 | — | 44 | ||||||||
Preferred securities | — | — | 14 | 14 | ||||||||
Total assets | $ | 597 | $ | 1,393 | $ | 14 | $ | 2,004 | ||||
| ||||||||||||
| (a) | Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s. |
| (b) | Other consists primarily of US agency securities. |
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At December 31, 2008, pension plan assets measured at fair value on a recurring basis consisted of the following:
Asset Category | Level 1 | Level 2 | Level 3 | Total | ||||||||
Interest-bearing cash | $ | — | $ | 141 | $ | — | $ | 141 | ||||
Equity securities: | ||||||||||||
US | 272 | 213 | — | 485 | ||||||||
International | 220 | 80 | — | 300 | ||||||||
Fixed income securities: | ||||||||||||
Corporate bonds (a) | — | 317 | — | 317 | ||||||||
US Treasuries | — | 368 | — | 368 | ||||||||
Other (b) | — | 110 | 1 | 111 | ||||||||
Preferred securities | — | — | 14 | 14 | ||||||||
Total assets | $ | 492 | $ | 1,229 | $ | 15 | $ | 1,736 | ||||
| ||||||||||||
| (a) | Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s. |
| (b) | Other consists primarily of US agency securities. |
The following table presents the changes in fair value of the Level 3 pension plan assets for the years ended December 31, 2009 and 2008:
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | ||||||
Balance at beginning of period | $ | 15 | $ | 14 | |||
Actual return on plan assets: | |||||||
Relating to assets held | (1 | ) | — | ||||
Relating to assets sold during the period | — | — | |||||
Purchases, sales and settlements | — | 1 | |||||
Transfers in and/or out of Level 3 | — | — | |||||
Balance at end of period | $ | 14 | $ | 15 | |||
Net unrealized gains (losses) included in net assets held at end of period | $ | — | $ | — | |||
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Detailed Information Regarding Postretirement Benefits Other Than Pensions
The following OPEB information is based on December 31, 2009, 2008, 2007 and October 10, 2007 measurement dates:
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Assumptions Used to Determine Net Periodic Benefit Cost: | ||||||||||||||||||
Discount rate | 6.85 | % | 6.55 | % | 6.45 | % | 5.90 | % | ||||||||||
Expected return on plan assets | 7.64 | % | 7.90 | % | 8.67 | % | 8.67 | % | ||||||||||
Components of Net Postretirement Benefit Cost: | ||||||||||||||||||
Service cost | $ | 10 | $ | 10 | $ | 3 | $ | 9 | ||||||||||
Interest cost | 61 | 59 | 14 | 41 | ||||||||||||||
Expected return on assets | (13 | ) | (20 | ) | (6 | ) | (15 | ) | ||||||||||
Amortization of net transition obligation | 1 | 1 | — | 1 | ||||||||||||||
Amortization of prior service cost/(credit) | (1 | ) | (1 | ) | — | (2 | ) | |||||||||||
Amortization of net loss | 12 | 9 | — | 15 | ||||||||||||||
Net periodic OPEB cost | $ | 70 | $ | 58 | $ | 11 | $ | 49 | ||||||||||
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Income: | ||||||||||||||||||
Net loss (gain) | $ | 15 | $ | 1 | $ | 36 | $ | (16 | ) | |||||||||
Transition obligation (asset) | — | — | — | — | ||||||||||||||
Prior service cost (credit) | — | — | — | — | ||||||||||||||
Amortization of net loss (gain) | — | — | — | — | ||||||||||||||
Amortization of transition obligation (asset) | — | — | — | — | ||||||||||||||
Amortization of prior service cost | — | — | — | 1 | ||||||||||||||
Reclassification to regulatory asset | — | (28 | ) | |||||||||||||||
Purchase accounting adjustment | — | (1 | ) | — | 13 | |||||||||||||
Total recognized in other comprehensive income | $ | 15 | $ | (28 | ) | $ | 36 | $ | (2 | ) | ||||||||
Total recognized in net periodic benefit cost and other comprehensive income | $ | 85 | $ | 30 | $ | 47 | $ | 47 | ||||||||||
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||
Assumptions Used to Determine Benefit Obligations at Period End: | ||||||||||||||
Discount rate | 5.90 | % | 6.85 | % | 6.55 | % | 6.45 | % | ||||||
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| Successor | ||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | |||||||
Change in Postretirement Benefit Obligation: | ||||||||
Benefit obligation at beginning of year | $ | 919 | $ | 928 | ||||
Service cost | 10 | 10 | ||||||
Interest cost | 61 | 59 | ||||||
Participant contributions | 23 | 16 | ||||||
Medicare Part D reimbursement | 6 | 4 | ||||||
Actuarial (gain)/loss | 108 | (35 | ) | |||||
Benefits paid | (64 | ) | (63 | ) | ||||
Benefit obligation at end of year | $ | 1,063 | $ | 919 | ||||
Change in Plan Assets: | ||||||||
Fair value of assets at beginning of year | $ | 198 | $ | 260 | ||||
Actual return (loss) on assets | 32 | (54 | ) | |||||
Employer contributions | 22 | 35 | ||||||
Participant contributions | 23 | 16 | ||||||
Medicare Part D reimbursement | — | 4 | ||||||
Benefits paid | (64 | ) | (63 | ) | ||||
Fair value of assets at end of year | $ | 211 | $ | 198 | ||||
Funded Status: | ||||||||
Benefit obligation | $ | (1,063 | ) | $ | (919 | ) | ||
Fair value of assets | 211 | 198 | ||||||
Funded status at end of year | $ | (852 | ) | $ | (721 | ) | ||
| Successor | ||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | |||||||
Amounts Recognized on the Balance Sheet Consist of: | ||||||||
Other noncurrent liabilities | $ | (852 | ) | $ | (721 | ) | ||
Amounts Recognized in Accumulated Other ComprehensiveIncome Consist of: | ||||||||
Net loss | $ | 23 | $ | 7 | ||||
Prior service cost credit | — | — | ||||||
Net transition obligation | — | — | ||||||
Net amount recognized | $ | 23 | $ | 7 | ||||
Amounts Recognized as Regulatory Assets Consist of: | ||||||||
Net loss | $ | 242 | $ | 174 | ||||
Prior service cost credit | (7 | ) | (8 | ) | ||||
Net transition obligation | 4 | 5 | ||||||
Net amount recognized | $ | 239 | $ | 171 | ||||
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The following tables provide information regarding the assumed health care cost trend rates.
| Successor | ||||||
| December 31, 2009 | December 31, 2008 | |||||
Assumed Health Care Cost Trend Rates-Not Medicare Eligible: | ||||||
Health care cost trend rate assumed for next year | 8.00 | % | 8.64 | % | ||
Rate to which the cost trend is expected to decline (the ultimate trend rate) | 5.00 | % | 5.00 | % | ||
Year that the rate reaches the ultimate trend rate | 2016 | 2017 | ||||
Assumed Health Care Cost Trend Rates-Medicare Eligible: | ||||||
Health care cost trend rate assumed for next year | 7.00 | % | 8.32 | % | ||
Rate to which the cost trend is expected to decline (the ultimate trend rate) | 5.00 | % | 5.00 | % | ||
Year that the rate reaches the ultimate trend rate | 2016 | 2017 | ||||
| 1-Percentage Point Increase | 1-Percentage Point Decrease | ||||||
Sensitivity Analysis of Assumed Health Care Cost Trend Rates: | |||||||
Effect on accumulated postretirement obligation | $ | 126 | $ | (105 | ) | ||
Effect on postretirement benefits cost | 10 | (8 | ) | ||||
OPEB Plan Investment Strategy and Asset 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.
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Fair Value Measurement of OPEB Plan Assets
At December 31, 2009, OPEB plan assets measured at fair value on a recurring basis consisted of the following:
Asset Category | Level 1 | Level 2 | Level 3 | Total | ||||||||
Interest-bearing cash | $ | — | $ | 18 | $ | — | $ | 18 | ||||
Equity securities: | ||||||||||||
US | 56 | 13 | — | 69 | ||||||||
International | 27 | 4 | — | 31 | ||||||||
Fixed income securities: | ||||||||||||
Corporate bonds (a) | — | 50 | — | 50 | ||||||||
US Treasuries | — | 1 | — | 1 | ||||||||
Other (b) | 39 | 2 | — | 41 | ||||||||
Preferred securities | — | — | 1 | 1 | ||||||||
Total assets | $ | 122 | $ | 88 | $ | 1 | $ | 211 | ||||
| ||||||||||||
| (a) | Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s. |
| (b) | Other consists primarily of US agency securities. |
At December 31, 2008, OPEB plan assets measured at fair value on a recurring basis consisted of the following:
Asset Category | Level 1 | Level 2 | Level 3 | Total | ||||||||
Interest-bearing cash | $ | — | $ | 19 | $ | — | $ | 19 | ||||
Equity securities: | ||||||||||||
US | 70 | 13 | — | 83 | ||||||||
International | 13 | 5 | — | 18 | ||||||||
Fixed income securities: | ||||||||||||
Corporate bonds (a) | — | 19 | — | 19 | ||||||||
US Treasuries | — | 22 | — | 22 | ||||||||
Other (b) | 29 | 7 | — | 36 | ||||||||
Preferred securities | — | — | 1 | 1 | ||||||||
Total assets | $ | 112 | $ | 85 | $ | 1 | $ | 198 | ||||
| ||||||||||||
| (a) | Substantially all corporate bonds are rated investment grade by a major ratings agency such as Moody’s. |
| (b) | Other consists primarily of US agency securities. |
There was no change in the fair values of Level 3 assets in the periods presented.
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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 | |||
Asset Class | Expected Long-Term Rate of Return | ||
US equity securities | 9.3 | % | |
International equity securities | 10.3 | % | |
Fixed income securities | 7.0 | % | |
Preferred securities | 8.0 | % | |
| 8.0 | % | ||
OPEB Plan | |||
Plan Type | Expected Long-Term Returns | ||
401(h) accounts | 8.0 | % | |
Life Insurance VEBA | 7.5 | % | |
Union VEBA | 7.5 | % | |
Non-Union VEBA | 4.00 | % | |
| 7.6 | % | ||
Significant Concentrations of Risk
The plans’ investments are exposed to risks such as interest rate, capital market and credit risks. We seek to optimize return on investment consistent with levels of liquidity and investment risk which are prudent and reasonable, given prevailing capital market conditions and other factors specific to us. While we recognize the importance of return, investments will be diversified in order to minimize the risk of large losses unless, under the circumstances, it is clearly prudent not to do so. There are also various restrictions and guidelines in place including limitations on types of investments allowed and portfolio weightings for certain investment securities to assist in the mitigation of the risk of large losses.
Assumed Discount Rate
We selected the assumed discount rate using the Hewitt Top Quartile yield curve, which is based on actual corporate bond yields and at December 31, 2009 consisted of 111 corporate bonds rated AA or higher as reported by either Moody’s or S&P.
Amortization in 2010
In 2010, we estimate amortization of the net actuarial loss and prior service cost for the defined benefit pension plan from accumulated other comprehensive income into net periodic benefit cost will be $51 million and $1 million, respectively. We estimate amortization of the net actuarial loss, prior service credit, and transition obligation for the OPEB plan from accumulated other comprehensive income into net periodic benefit cost will be $21 million, a $1 million credit and $1 million, respectively.
Contributions in 2010
Estimated funding for calendar year 2010 totals $45 million for the Retirement Plan and $24 million for the OPEB plan.
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Future Benefit Payments
Estimated future benefit payments to beneficiaries are as follows:
| Successor | ||||||||||||||||||
| 2010 | 2011 | 2012 | 2013 | 2014 | 2015-19 | |||||||||||||
Pension benefits | $ | 142 | $ | 149 | $ | 161 | $ | 171 | $ | 173 | $ | 1,020 | ||||||
OPEB | $ | 54 | $ | 57 | $ | 60 | $ | 63 | $ | 67 | $ | 377 | ||||||
Medicare Part D subsidies received | $ | 6 | $ | 7 | $ | 7 | $ | 8 | $ | 8 | $ | 49 | ||||||
Thrift Plan
Our employees may participate in a qualified savings plan, the Thrift Plan. This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. The Thrift Plan included an employee stock ownership component until October 10, 2007. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under applicable law. Employees who earn more than such threshold may contribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% of the first 6% of employee contributions for employees who are covered under the Cash Balance Formula of the Retirement Plan, and 75% of the first 6% of employee contributions for employees who are covered under the Traditional Retirement Plan Formula of the Retirement Plan. Effective January 1, 2006 through October 10, 2007, employees could reallocate or transfer all or part of their accumulated or future employer matching contributions to any of the plan’s other investment options. As of October 10, 2007, employer matching contributions are made in cash and may be allocated by participants to any of the plan’s investment options. Our contributions to the Thrift Plan totaled $28 million, $25 million, $6 million and $33 million in the years ended December 31, 2009 and 2008, the period October 11, 2007 through December 31, 2007 and the period January 1, 2007 through October 10, 2007, respectively. See Note 14 for additional information related to the Thrift Plan.
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| 22. | STOCK-BASED COMPENSATION |
Successor – EFH Corp. 2007 Stock Incentive Plan
In December 2007, we established the 2007 Stock Incentive Plan for Key Employees of EFH Corp. and its Affiliates (2007 SIP). Incentive awards under the 2007 SIP may be granted to directors and officers and qualified managerial employees of EFH Corp. or its subsidiaries or affiliates in the form of non-qualified stock options, stock appreciation rights, restricted shares, deferred shares, shares of common stock, the opportunity to purchase shares of common stock and other awards that are valued in whole or in part by reference to, or are otherwise based on the fair market value of EFH Corp.’s shares of common stock. The 2007 SIP permits the grant of awards for 72 million shares of common stock, subject to adjustments under applicable laws for certain events, such as a change in control, and no such grants may be issued after December 26, 2017. Shares related to grants that are forfeited, terminated, cancelled, expire unexercised, withheld to satisfy tax withholding obligations, or are repurchased by the Company are available for new grants under the 2007 SIP.
Stock Options— Under the terms of the 2007 SIP, options to purchase 14.7 million, 33.1 million and 19.5 million shares of EFH Corp. common stock were granted to certain management employees in 2009, 2008 and December 2007, respectively. Of the options granted in 2009, 9.2 million were granted in exchange for previously granted options. Vested awards must be exercised within 10 years of the grant date. The options initially provided the holder the right to purchase EFH Corp. common stock for $5.00 per share. The terms of the options were fixed at grant date. The stock option awards under the 2007 SIP consist of three types of stock options. One-half of the options initially granted vest solely based upon continued employment over a specific period of time, generally five years, with the options vesting ratably on an annual basis over the period (Time-Based Options). One-half of the options initially granted vest based upon both continued employment and the achievement of targeted five-year EFH Corp. EBITDA levels (Performance-Based Options). The Performance-Based Options may also vest in part or in full upon the occurrence of certain specified liquidity events. All options remain exercisable for ten years from the date of grant. Prior to vesting, expenses are recorded if the achievement of the EBITDA levels is probable, and amounts recorded are adjusted or reversed if the probability of achievement of such levels changes. Probability of vesting is evaluated at least each quarter.
In October 2009, in consideration of the recent economic dislocation and the desire to provide incentives for retention, grantees of Performance-Based Options (excluding named executive officers and a small group of other employees) were provided an offer, which substantially all accepted, to exchange their unvested Performance-Based Options granted under the 2007 SIP with a strike price of $5.00 per share and a vesting schedule through October 2012 for new time-based stock options (Cliff-Vesting Options) granted under the 2007 SIP with a strike price of $3.50 per share (the then most recent market valuation of each share), with one-half of these options vesting in September 2012 and one-half of these options vesting in September 2014. Additionally, 3.1 million Cliff-Vesting Options were granted to certain Named Executive Officers and a small group of other employees under the 2007 SIP with a strike price of $3.50 per share, vesting in September 2014. Substantially all of this group of employees also accepted an offer to exchange half of their unvested Performance-Based Options under the 2007 SIP with a strike price of $5.00 per share and a vesting schedule through December 2012 for new time-based stock options granted under the 2007 SIP with a strike price of $3.50 per share, vesting in September 2014.
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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| Successor | ||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | |||||||
Assumptions | Time-Based Options | Performance-Based Options | ||||||||||
Expected volatility | 30% | 30% – 33% | 30% | 30% | 30%–33% | 30% | ||||||
Expected annual dividend | — | — | — | — | — | — | ||||||
Expected life (in years) | 6.4–7.4 | 6.0–6.5 | 6.4 | 5.3–7.6 | 5.0–7.3 | 5.4–7.4 | ||||||
Risk-free rate | 2.54%–3.14% | 1.51%–3.50% | 3.81% | 2.51%–3.25% | 1.35%–3.64% | 3.92% | ||||||
The weighted average grant-date fair value of the Time-Based Options granted in 2009, 2008 and December 2007 was $1.32, $1.89 and $1.92 per option, respectively. The weighted-average grant-date fair value of the Performance-Based Options granted in 2009, 2008 and December 2007 ranged from $1.16 to $1.91, $1.73 to $2.25 and $1.74 to $2.09, respectively, depending upon the performance period.
Compensation expense for Time-Based Options is based on the grant-date fair value and recognized over the vesting period as employees perform services. During 2009, 2008 and the 2007 Successor period, $8.6 million, $11.9 million and less than $100,000, respectively, was recognized as expense for Time-Based Options.
As of December 31, 2009, there was approximately $48.9 million of unrecognized compensation expense related to nonvested Time-Based Options, which is expected to be recognized ratably over a remaining weighted-average period of approximately three to five years.
A summary of Time-Based Options activity is presented below:
| Year Ended December 31, 2009 | |||||||||
Options | Options (millions) | Weighted Average Exercise Price | Aggregate Intrinsic Value (millions) | ||||||
Total outstanding at beginning of period | 24.6 | $ | 5.00 | $ | — | ||||
Granted | 13.9 | 3.50 | — | ||||||
Exercised | — | — | — | ||||||
Forfeited | (2.9 | ) | 5.00 | — | |||||
Total outstanding at end of period (weighted average remaining term of 8 – 10 years) | 35.6 | 4.42 | — | ||||||
Exercisable at end of period (weighted average remaining term of 8 – 10 years) | (4.7 | ) | 5.00 | — | |||||
Expected forfeitures | (0.3 | ) | 5.00 | — | |||||
Expected to vest at end of period (weighted average remaining term of 8 – 10 years) | 30.6 | 4.32 | — | ||||||
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| Year Ended December 31, 2008 | |||||||||
Options | Options (millions) | Weighted Average Exercise Price | Aggregate Intrinsic Value (millions) | ||||||
Total outstanding at beginning of period | 9.8 | $ | 5.00 | $ | — | ||||
Granted | 16.8 | 5.00 | — | ||||||
Exercised | — | — | — | ||||||
Forfeited | (2.0 | ) | 5.00 | — | |||||
Total outstanding at end of period (weighted average remaining term of 9 years) | 24.6 | 5.00 | — | ||||||
Exercisable at end of period (weighted average remaining term of 9 years) | (4.7 | ) | 5.00 | — | |||||
Expected forfeitures | (0.4 | ) | 5.00 | — | |||||
Expected to vest at end of period (weighted average remaining term of 9 years) | 19.5 | 5.00 | — | ||||||
| Period from October 11, 2007 through December 31, 2007 | |||||||||
Options | Options (millions) | Weighted Average Exercise Price | Aggregate Intrinsic Value (millions) | ||||||
Total outstanding at beginning of period | — | $ | — | $ | — | ||||
Granted | 9.8 | 5.00 | — | ||||||
Exercised | — | — | — | ||||||
Forfeited | — | — | — | ||||||
Total outstanding at end of period (weighted average remaining term of 10 years) | 9.8 | 5.00 | — | ||||||
Exercisable at end of period (weighted average remaining term of 10 years) | — | — | — | ||||||
Expected forfeitures | (0.5 | ) | 5.00 | — | |||||
Expected to vest at end of period (weighted average remaining term of 10 years) | 9.3 | 5.00 | — | ||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | |||||||||||||||
Nonvested Options | Options (millions) | Weighted Average Grant- Date Fair Value | Options (millions) | Weighted Average Grant- Date Fair Value | Options (millions) | Grant- Date Fair Value | |||||||||||
Total nonvested at beginning of period | 19.9 | $ | 2.05 | 9.8 | $ | 1.92 | — | $ | — | ||||||||
Granted | 13.9 | 1.32 | 16.8 | 1.89 | 9.8 | 1.92 | |||||||||||
Vested | (4.7 | ) | 1.86 | (4.7 | ) | 1.80 | — | — | |||||||||
Forfeited | (2.9 | ) | 1.85 | (2.0 | ) | 1.92 | — | — | |||||||||
Total nonvested at end of period | 26.2 | 1.67 | 19.9 | 2.05 | 9.8 | 1.92 | |||||||||||
Compensation expense for Performance-Based Options is based on the grant-date fair value and recognized over the requisite performance and service periods for each tranche of options depending upon the achievement of financial performance, or if certain liquidity events occur, as discussed above. No amounts were expensed in 2009 for Performance-Based Options because the 2009 EBITDA target was not met. Additionally, most participants’ Performance-Based Options were exchanged for Time-Based Options in 2009. Expense recognized for Performance-Based Options in 2008 totaled $8.1 million. No amounts were expensed in the 2007 Successor period for Performance-Based Options because the performance period for the first tranche of the options did not begin until January 1, 2008.
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As of December 31, 2009, there was approximately $19.1 million of unrecognized compensation expense related to nonvested Performance-Based Options, which we could record as an expense over a remaining weighted-average period of approximately three to five years, subject to the achievement of financial performance being probable. A total of 4.8 million of the 2008 and none of the 2009 Performance-Based Options have vested.
A summary of Performance-Based Options activity is presented below:
| Year Ended December 31, 2009 | |||||||||
Options | Options (millions) | Weighted Average Exercise Price | Aggregate Intrinsic Value (millions) | ||||||
Outstanding at beginning of period | 23.9 | $ | 5.00 | $ | — | ||||
Granted | 0.8 | 3.50 | — | ||||||
Exercised | — | — | — | ||||||
Forfeited | (3.0 | ) | 5.00 | — | |||||
Exchanged | (9.2 | ) | 5.00 | — | |||||
Total outstanding at end of period (weighted average remaining term of 8 – 10 years) | 12.5 | 4.90 | — | ||||||
Exercisable at end of period (weighted average remaining term of 8 – 10 years) | (4.8 | ) | 5.00 | — | |||||
Expected forfeitures | (0.3 | ) | 5.00 | — | |||||
Expected to vest at end of period (weighted average remaining term of 8 – 10 years) | 7.4 | 4.90 | — | ||||||
| Year Ended December 31, 2008 | |||||||||
Options | Options (millions) | Weighted Average Exercise Price | Aggregate Intrinsic Value (millions) | ||||||
Outstanding at beginning of period | 9.8 | $ | 5.00 | $ | — | ||||
Granted | 16.2 | 5.00 | — | ||||||
Exercised | — | — | — | ||||||
Forfeited | (2.1 | ) | 5.00 | — | |||||
Total outstanding at end of period (weighted average remaining term of 9 years) | 23.9 | 5.00 | — | ||||||
Exercisable at end of period (weighted average remaining term of 9 years) | — | — | — | ||||||
Expected forfeitures | (0.5 | ) | 5.00 | — | |||||
Expected to vest at end of period (weighted average remaining term of 9 years) | 23.4 | 5.00 | — | ||||||
| Period from October 11, 2007 through December 31, 2007 | |||||||||
Options | Options (millions) | Weighted Average Exercise Price | Aggregate Intrinsic Value (millions) | ||||||
Outstanding at beginning of period | — | $ | — | $ | — | ||||
Granted | 9.8 | 5.00 | — | ||||||
Exercised | — | — | — | ||||||
Forfeited | — | — | — | ||||||
Total outstanding at end of period (weighted average remaining term of 10 years) | 9.8 | 5.00 | — | ||||||
Exercisable at end of period (weighted average remaining term of 10 years) | — | — | — | ||||||
Expected forfeitures | (0.5 | ) | 5.00 | — | |||||
Expected to vest at end of period (weighted average remaining term of 10 years) | 9.3 | 5.00 | — | ||||||
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| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | |||||||||||||||
Nonvested Options | Options (millions) | Grant-Date Fair Value | Options (millions) | Grant-Date Fair Value | Options (millions) | Grant-Date Fair Value | |||||||||||
Total nonvested at beginning of period | 23.9 | $ | 1.73 – 2.21 | 9.8 | $ | 1.74 – 2.09 | — | $ | — | ||||||||
Granted | 0.8 | 1.16 – 1.91 | 16.2 | 1.73 – 2.25 | 9.8 | 1.74 – 2.09 | |||||||||||
Vested | (4.8 | ) | 1.73 – 2.21 | — | — | — | — | ||||||||||
Forfeited | (3.0 | ) | 1.73 – 2.21 | (2.1 | ) | 1.74 – 2.09 | — | — | |||||||||
Exchanged | (9.2 | ) | — | — | — | — | — | ||||||||||
Total nonvested at end of period | 7.7 | 1.16 – 2.11 | 23.9 | 1.73 – 2.21 | 9.8 | 1.74 – 2.09 | |||||||||||
Other Share and Share-Based Awards — In 2008, we granted 2.4 million deferred share awards, each of which represents the right to receive one share of EFH Corp. stock, to certain management employees who agreed to forego share-based awards that vested at the Merger date. The deferred share awards are fully vested and are payable in cash or stock upon the earlier of a change of control or separation of service. No expense was recorded in 2008 related to these awards. An additional 1.2 million deferred share awards were granted to certain management employees in 2008, approximately half of which are payable in cash or stock and the balance payable in stock; these awards vest over periods of one to five years, and $3.7 million and $2.2 million in expense was recorded in 2009 and 2008, respectively, to recognize the vesting. In 2009, 120 thousand deferred share awards were surrendered by an employee upon termination of employment. Deferred share awards that are payable in cash or stock are accounted for as liability awards; therefore, the effects of changes in value of EFH Corp. shares are recognized in earnings.
We granted 1.5 million shares of EFH Corp. stock in 2009, 1.7 million shares in 2008 and 1.0 million shares in 2007, to board members and other non-employees. The shares vest over periods of one to two years, and a portion may be settled in cash. Expense recognized in 2009, 2008 and 2007 related to these grants totaled $4.0 million, $8.2 million and $1 million, respectively.
Stock Appreciation Rights –In 2008, Oncor established the Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan (the SARs Plan) under which certain employees of Oncor and its subsidiaries may be granted stock appreciation rights (SARs) payable in cash, or in some circumstances, Oncor units. Two types of SARs may be granted under the SARs Plan. Time-based SARs (Time SARs) vest solely based upon continued employment ratably on an annual basis on each of the first five anniversaries of the grant date. Performance-based SARs (Performance SARs) vest based upon both continued employment and the achievement of a predetermined level of Oncor EBITDA over time, generally ratably over five years based upon annual Oncor EBITDA levels, with provisions for vesting if the annual levels are not achieved but cumulative two- or three-year total Oncor EBITDA levels are achieved. Time and Performance SARs may also vest in part or in full upon the occurrence of certain specified liquidity events and are exercisable only upon the occurrence of certain specified liquidity events. Since the exercisability of the Time and Performance SARs is conditioned upon the occurrence of a liquidity event, compensation expense will not be recorded until it is probable that a liquidity event will occur. Generally, awards under the SARs Plan terminate on the tenth anniversary of the grant, unless the participant’s employment is terminated earlier under certain circumstances.
In February 2009, Oncor implemented a similar plan for primarily non-employee members of Oncor’s board of directors. The terms and conditions are similar to the SARs Plan with the exception that SARs granted to non-employee board members vest in eight equal quarterly installments over a two-year period.
SARs are generally payable in cash based on the fair market value of the SAR on the date of exercise. No SARs were granted under the SARs Plan during the year ended December 31, 2009. Oncor granted 6.9 million Time SARs under the SARs Plan during the year ended December 31, 2008, and Time SARS vested at December 31, 2009 totaled 2.8 million. Oncor granted 6.9 million Performance SARs under the SARs Plan during the year ended December 31, 2008, and Performance SARs vested at December 31, 2009 totaled 1.4 million. Oncor granted 55 thousand SARs under the Director SARs Plan during the year ended December 31, 2009, and SARs vested under the Director SARs Plan at December 31, 2009 totaled 27.5 thousand. There were no SARs under either plan eligible for exercise at December 31, 2009.
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Predecessor
Under our shareholder-approved long-term incentive plans, we provided discretionary awards to qualified management employees payable in EFH Corp. common stock. As presented below, the awards generally vested over a three-year period and the number of shares ultimately earned was based on the performance of EFH Corp.’s stock over the vesting period.
Awards Granted in 2007 | ||
Vesting period | Three years | |
Potential share pay-out as a percent of initial number of awards granted | 0% to 100% (a) | |
Basis for pay-out percentage — actual EFH Corp. three-year share return compared to: | Share returns of companies comprising the S&P 500 Electric Utilities Index | |
Award type | Performance units payable in EFH Corp. stock upon vesting | |
| (a) | For a small number of employees under employment agreements, potential share pay-out as a percent of initial number of awards granted was 0% to 200%, and the number of shares distributed was based 100% on EFH Corp.’s total share return over the vesting period compared to the total returns of companies comprising the Standard & Poor’s 500 Electric Utilities Index. |
In addition, we established restrictions that limited certain employees’ opportunities to liquidate vested awards. For both restricted stock and performance unit awards, dividends over the vesting periods were converted to equivalent shares of EFH Corp. common stock to be distributed upon vesting.
The determination of the fair value of stock-based compensation awards at grant date was based on a Monte Carlo simulation. The more significant assumptions used in this valuation process were as follows:
| • | Expected volatility of the stock price of EFH Corp. and peer group companies – expected volatility was determined based on historical stock price volatilities using daily stock price returns for the three years prior to the grant date. |
| • | The dividend rate for EFH Corp. and peer group companies was based on the observed dividend payments over the twelve months prior to grant date. |
| • | Risk-free rate (three-year US Treasury securities) during the three year vesting period. |
| • | Discount for liquidation restrictions – this factor estimated the discount for lack of marketability of vested awards due to the anticipated time for the approval and issuance of the awards, the black-out period immediately after the grant and additional holding requirements imposed on senior executives. This discount was determined based on an estimation of the cost of a protective put at the award date and is calculated using the Black-Scholes option pricing model using expected volatility assumptions based on historical and implied volatility as discussed above and a risk-free rate of return over the option period. |
| • | Change-in-control and no-change-in-control scenarios were considered. The change-in-control scenario was based on three different change-in-control dates each assigned projected probabilities. The change-in-control value was probability weighted with the value assuming no change of control |
Assumptions | Period from January 1, 2007 through October 10, 2007 | |
Expected volatility | 29% – 30% | |
Expected annual dividend | — | |
Risk-free rate | 4.8% – 4.9% | |
Discount for liquidity restrictions | 0% – 4.8% |
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The following table presents information about Predecessor stock-based compensation plans.
| Number of awards: | Performance Unit Awards | |||
Balance — December 31, 2006 | 4,250,340 | |||
Granted in period from January 1, 2007 to October 10, 2007 | 474,000 | |||
Forfeited/expired | (41,492 | ) | ||
Vested/exercised | (4,682,848 | ) | ||
Balance at Merger closing date | — | |||
Weighted average fair value — Period from January 1, 2007 through October 10, 2007 | ||||
Outstanding — Beginning of year | $ | 23.60 | ||
Granted | $ | 67.08 | ||
Forfeited | $ | 36.24 | ||
Vested | $ | 28.30 | ||
Outstanding — October 10, 2007 | $ | — | ||
Weighted average fair value of awards granted in | ||||
Period from January 1, 2007 to October 10, 2007 | $ | 67.08 | ||
The table above reflects the weighted average fair value of the awards on grant date.
Reported expense related to the awards totaled $27 million ($18 million after-tax) in the period from January 1, 2007 through October 10, 2007. Such expenses are reported in SG&A expense, except for immaterial amounts capitalized.
The fair value of awards that vested in the period from January 1, 2007 through October 10, 2007 totaled $613 million based on the vesting date share prices.
Under the terms of the Merger Agreement, all outstanding Performance Unit awards were deemed to be vested at the date of the Merger. See Note 2.
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| 23. | RELATED PARTY TRANSACTIONS |
We incur an annual management fee under the terms of a management agreement with the Sponsor Group for which we accrued $36 million, $35 million and $8 million for the years ended December 31, 2009 and 2008 and the period October 11, 2007 to December 31, 2007, respectively. The fee is reported as SG&A expense in Corporate and Other activities. Also, under terms of the management agreement, affiliates of the Sponsor Group and Lehman Brothers Inc. were paid transaction fees of $300 million for certain services provided in connection with the Merger and related transactions. A portion of these fees was included in the purchase price that was allocated to identifiable assets and liabilities as part of purchase accounting, and the remainder was reported as deferred financing costs.
At the closing of the Merger, TCEH entered into the TCEH Senior Secured Facilities and Oncor entered into a revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners, which is a member of the Sponsor Group. Affiliates of GS Capital Partners and Kohlberg Kravis Roberts & Co. L.P. (a member of the Sponsor Group) have from time to time engaged in commercial banking and financial advisory transactions with us in the normal course of business.
Affiliates of the Sponsor Group participated in debt exchange offers completed in November 2009 by EFH Corp., Intermediate Holding and EFIH Finance to exchange new senior secured notes for certain EFH Corp. and TCEH notes as discussed in Note 12 and in an EFH Corp. issuance of $500 million principal amount of senior secured notes completed in January 2010. Goldman, Sachs & Co. and KKR Capital Markets LLC acted as dealer managers and TPG Capital, L.P. served as an advisor in the exchange offers. Goldman, Sachs & Co. also acted as an initial purchaser in the issuance of senior secured notes. (See Note 12 for additional information.) These affiliates were compensated for their services in accordance with the terms of the respective agreements. These fees totaled $1 million for the year ended December 31, 2009.
Affiliates of Goldman Sachs & Co. are parties to certain commodity and interest rate hedging transactions with us in the normal course of business.
Affiliates of the Sponsor Group may sell or acquire debt or debt securities issued by us in open market transactions or through loan syndications.
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| 24. | SEGMENT INFORMATION |
Our operations are aligned into two reportable business segments: Competitive Electric and Regulated Delivery. The segments are managed separately because they are strategic business units that offer different products or services and involve different risks.
The Competitive Electric segment is engaged in competitive market activities consisting of electricity generation, the development and construction of new generation facilities, wholesale energy sales and purchases, commodity risk management and trading activities, and retail electricity sales to residential and business customers, all largely in Texas. These activities are conducted by TCEH. The results of this segment also include equipment salvage and resale activities related to the 2007 cancellation of the development of eight new coal-fueled generation units discussed in Note 4.
The Regulated Delivery segment is engaged in regulated electricity transmission and distribution operations in Texas. These activities are conducted by Oncor, including its wholly owned bankruptcy-remote financing subsidiary.
Corporate and Other represents the remaining nonsegment operations consisting primarily of discontinued operations, general corporate expenses and interest on EFH Corp., Intermediate Holding and EFC Holdings debt.
The accounting policies of the business segments are the same as those described in the summary of significant accounting policies in Note 1. We evaluate performance based on income from continuing operations. We account for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.
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| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Operating Revenues | ||||||||||||||||||
Competitive Electric | $ | 7,911 | $ | 9,787 | $ | 1,671 | $ | 6,884 | ||||||||||
Regulated Delivery | 2,690 | 2,580 | 532 | 1,987 | ||||||||||||||
Corp. and Other | 20 | 37 | 11 | 37 | ||||||||||||||
Eliminations | (1,075 | ) | (1,040 | ) | (220 | ) | (864 | ) | ||||||||||
Consolidated | $ | 9,546 | $ | 11,364 | $ | 1,994 | $ | 8,044 | ||||||||||
Regulated Revenues — Included in Operating Revenues | ||||||||||||||||||
Competitive Electric | $ | — | $ | — | $ | — | $ | — | ||||||||||
Regulated Delivery | 2,690 | 2,580 | 532 | 1,987 | ||||||||||||||
Corp. and Other | — | — | — | — | ||||||||||||||
Eliminations | (1,051 | ) | (1,001 | ) | (208 | ) | (824 | ) | ||||||||||
Consolidated | $ | 1,639 | $ | 1,579 | $ | 324 | $ | 1,163 | ||||||||||
Affiliated Revenues — Included in Operating Revenues | ||||||||||||||||||
Competitive Electric | $ | 8 | $ | 7 | $ | 2 | $ | 5 | ||||||||||
Regulated Delivery | 1,051 | 1,001 | 208 | 824 | ||||||||||||||
Corp. and Other | 16 | 32 | 10 | 35 | ||||||||||||||
Eliminations | (1,075 | ) | (1,040 | ) | (220 | ) | (864 | ) | ||||||||||
Consolidated | $ | — | $ | — | $ | — | $ | — | ||||||||||
Depreciation and Amortization | ||||||||||||||||||
Competitive Electric | $ | 1,172 | $ | 1,092 | $ | 315 | $ | 253 | ||||||||||
Regulated Delivery | 557 | 492 | 96 | 366 | ||||||||||||||
Corp. and Other | 25 | 26 | 4 | 15 | ||||||||||||||
Eliminations | — | — | — | — | ||||||||||||||
Consolidated | $ | 1,754 | $ | 1,610 | $ | 415 | $ | 634 | ||||||||||
Equity in Earnings (Losses) of Unconsolidated Subsidiaries (a) | ||||||||||||||||||
Competitive Electric | $ | (7 | ) | $ | (10 | ) | $ | (2 | ) | $ | (5 | ) | ||||||
Regulated Delivery | (2 | ) | (4 | ) | (1 | ) | (2 | ) | ||||||||||
Corp. and Other | (3 | ) | (5 | ) | (1 | ) | (4 | ) | ||||||||||
Eliminations | 12 | 19 | 4 | 10 | ||||||||||||||
Consolidated | $ | — | $ | — | $ | — | $ | (1 | ) | |||||||||
Interest Income | ||||||||||||||||||
Competitive Electric | $ | 64 | $ | 61 | $ | 10 | $ | 271 | ||||||||||
Regulated Delivery | 43 | 45 | 12 | 44 | ||||||||||||||
Corp. and Other | 147 | 100 | 42 | 106 | ||||||||||||||
Eliminations | (209 | ) | (179 | ) | (40 | ) | (365 | ) | ||||||||||
Consolidated | $ | 45 | $ | 27 | $ | 24 | $ | 56 | ||||||||||
Interest Expense and Related Charges | ||||||||||||||||||
Competitive Electric | $ | 1,946 | $ | 4,010 | $ | 609 | $ | 357 | ||||||||||
Regulated Delivery | 346 | 317 | 70 | 242 | ||||||||||||||
Corp. and Other | 829 | 787 | 200 | 437 | ||||||||||||||
Eliminations | (209 | ) | (179 | ) | (40 | ) | (365 | ) | ||||||||||
Consolidated | $ | 2,912 | $ | 4,935 | $ | 839 | $ | 671 | ||||||||||
Income Tax Expense (Benefit) | ||||||||||||||||||
Competitive Electric | $ | 407 | $ | (450 | ) | $ | (656 | ) | $ | 306 | ||||||||
Regulated Delivery | 173 | 221 | 30 | 160 | ||||||||||||||
Corp. and Other | (213 | ) | (242 | ) | (47 | ) | (157 | ) | ||||||||||
Eliminations | — | — | — | — | ||||||||||||||
Consolidated | $ | 367 | $ | (471 | ) | $ | (673 | ) | $ | 309 | ||||||||
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| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Income (loss) from Continuing Operations | ||||||||||||||||||
Competitive Electric | $ | 631 | $ | (8,929 | ) | $ | (1,245 | ) | $ | 722 | ||||||||
Regulated Delivery | 320 | (486 | ) | 63 | 265 | |||||||||||||
Corp. and Other | (543 | ) | (583 | ) | (179 | ) | (288 | ) | ||||||||||
Eliminations | — | — | — | — | ||||||||||||||
Consolidated | $ | 408 | $ | (9,998 | ) | $ | (1,361 | ) | $ | 699 | ||||||||
Investment in Equity Investees | ||||||||||||||||||
Competitive Electric | $ | 42 | $ | (2 | ) | $ | (1 | ) | ||||||||||
Regulated Delivery | — | — | — | |||||||||||||||
Corp. and Other | — | — | — | |||||||||||||||
Eliminations | — | — | — | |||||||||||||||
Consolidated | $ | 42 | $ | (2 | ) | $ | (1 | ) | ||||||||||
Total assets (b) | ||||||||||||||||||
Competitive Electric | $ | 43,302 | $ | 43,061 | $ | 49,297 | ||||||||||||
Regulated Delivery | 16,246 | 15,772 | 15,458 | |||||||||||||||
Corp. and Other | 4,355 | 3,526 | 2,992 | |||||||||||||||
Eliminations | (4,241 | ) | (3,096 | ) | (2,943 | ) | ||||||||||||
Consolidated | $ | 59,662 | $ | 59,263 | $ | 64,804 | ||||||||||||
Capital Expenditures | ||||||||||||||||||
Competitive Electric | $ | 1,324 | $ | 1,914 | $ | 530 | $ | 1,901 | ||||||||||
Regulated Delivery | 998 | 919 | 162 | 580 | ||||||||||||||
Corp. and Other | 26 | 16 | 1 | 7 | ||||||||||||||
Eliminations | — | — | — | — | ||||||||||||||
Consolidated | $ | 2,348 | $ | 2,849 | $ | 693 | $ | 2,488 | ||||||||||
| (a) | Amounts invested in equity investees were not material in any period presented. |
| (b) | Assets by segment exclude investments in affiliates. |
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| 25. | SUPPLEMENTARY FINANCIAL INFORMATION |
Regulated Versus Unregulated Operations
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Operating revenues | ||||||||||||||||||
Regulated | $ | 2,690 | $ | 2,580 | $ | 532 | $ | 1,987 | ||||||||||
Unregulated | 7,931 | 9,824 | 1,682 | 6,921 | ||||||||||||||
Intercompany sales eliminations — regulated | (1,051 | ) | (1,001 | ) | (208 | ) | (824 | ) | ||||||||||
Intercompany sales eliminations — unregulated | (24 | ) | (39 | ) | (12 | ) | (40 | ) | ||||||||||
Total operating revenues | 9,546 | 11,364 | 1,994 | 8,044 | ||||||||||||||
Fuel, purchased power and delivery fees — unregulated (a) | (2,878 | ) | (4,595 | ) | (644 | ) | (2,381 | ) | ||||||||||
Net gain (loss) from commodity hedging and trading activities — unregulated | 1,736 | 2,184 | (1,492 | ) | (554 | ) | ||||||||||||
Operating costs — regulated | (908 | ) | (828 | ) | (182 | ) | (637 | ) | ||||||||||
Operating costs — unregulated | (690 | ) | (675 | ) | (124 | ) | (470 | ) | ||||||||||
Depreciation and amortization — regulated | (557 | ) | (492 | ) | (96 | ) | (366 | ) | ||||||||||
Depreciation and amortization — unregulated | (1,197 | ) | (1,118 | ) | (319 | ) | (268 | ) | ||||||||||
Selling, general and administrative expenses — regulated | (194 | ) | (164 | ) | (45 | ) | (134 | ) | ||||||||||
Selling, general and administrative expenses — unregulated | (874 | ) | (793 | ) | (171 | ) | (557 | ) | ||||||||||
Franchise and revenue-based taxes — regulated | (250 | ) | (255 | ) | (62 | ) | (198 | ) | ||||||||||
Franchise and revenue-based taxes — unregulated | (109 | ) | (108 | ) | (31 | ) | (84 | ) | ||||||||||
Impairment of goodwill | (90 | ) | (8,860 | ) | — | — | ||||||||||||
Other income | 204 | 80 | 14 | 69 | ||||||||||||||
Other deductions | (97 | ) | (1,301 | ) | (61 | ) | (841 | ) | ||||||||||
Interest income | 45 | 27 | 24 | 56 | ||||||||||||||
Interest expense and other charges | (2,912 | ) | (4,935 | ) | (839 | ) | (671 | ) | ||||||||||
Income (loss) from continuing operations before income taxes | $ | 775 | $ | (10,469 | ) | $ | (2,034 | ) | $ | 1,008 | ||||||||
| (a) | Includes unregulated cost of fuel consumed of $1.269 billion in 2009, $1.604 billion in 2008, $255 million in the period from October 11, 2007 through December 31, 2007 and $868 million in the period from January 1, 2007 through October 10, 2007. The balance represents energy purchased for resale and delivery fees net of intercompany eliminations. |
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Interest Expense and Related Charges
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Interest paid/accrued (including net amounts settled/accrued under interest rate swaps) | $ | 3,479 | $ | 3,482 | $ | 800 | $ | 722 | ||||||||||
Unrealized mark-to-market net (gain) loss on interest rate swaps | (696 | ) | 1,477 | — | — | |||||||||||||
Amortization of interest rate swap losses at dedesignation of hedge accounting | 184 | 66 | — | 10 | ||||||||||||||
Amortization of fair value debt discounts resulting from purchase accounting | 82 | 75 | 17 | — | ||||||||||||||
Amortization of debt issuance costs and discounts | 140 | 146 | 81 | 19 | ||||||||||||||
Capitalized interest, primarily related to generation facility and regulated utility asset construction | (277 | ) | (311 | ) | (59 | ) | (80 | ) | ||||||||||
Total interest expense and related charges | $ | 2,912 | $ | 4,935 | $ | 839 | $ | 671 | ||||||||||
Restricted Cash
| Successor | ||||||||||||
| At December 31, 2009 | At December 31, 2008 | |||||||||||
| Current Assets | Noncurrent Assets | Current Assets | Noncurrent Assets | |||||||||
Amounts related to TCEH’s Letter of Credit Facility (See Note 12) | $ | — | $ | 1,135 | $ | — | $ | 1,250 | ||||
Amounts related to margin deposits held | 1 | — | 4 | — | ||||||||
Amounts related to securitization (transition) bonds | 47 | 14 | 51 | 17 | ||||||||
Total restricted cash | $ | 48 | $ | 1,149 | $ | 55 | $ | 1,267 | ||||
Inventories by Major Category
| Successor | ||||||
| December 31, 2009 | December 31, 2008 | |||||
Materials and supplies | $ | 248 | $ | 199 | ||
Fuel stock | 204 | 162 | ||||
Natural gas in storage | 33 | 65 | ||||
Total inventories | $ | 485 | $ | 426 | ||
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Property, Plant and Equipment
| Successor | ||||||
| December 31, 2009 | December 31, 2008 | |||||
Competitive Electric: | ||||||
Generation and mining | $ | 20,755 | $ | 16,954 | ||
Nuclear fuel (net of accumulated amortization of $426 and $235) | 430 | 433 | ||||
Other assets | 27 | 16 | ||||
Regulated Delivery: | ||||||
Transmission | 3,917 | 3,626 | ||||
Distribution | 8,778 | 8,429 | ||||
Other assets | 174 | 166 | ||||
Corporate and Other | 161 | 138 | ||||
Total | 34,242 | 29,762 | ||||
Less accumulated depreciation | 6,633 | 5,321 | ||||
Net of accumulated depreciation | 27,609 | 24,441 | ||||
Construction work in progress: | ||||||
Competitive Electric | 2,163 | 4,852 | ||||
Regulated Delivery | 321 | 213 | ||||
Corporate and Other | 15 | 16 | ||||
Total construction work in progress | 2,499 | 5,081 | ||||
Property, plant and equipment — net | $ | 30,108 | $ | 29,522 | ||
Depreciation expense totaled $1.454 billion, $1.355 billion, $297 million and $467 million for the years ended December 31, 2009 and 2008, the period October 11, 2007 through December 31, 2007 and the period January 1, 2007 through October 10, 2007, respectively, including $394 million, $330 million, $63 million and $235 million, respectively, related to Oncor.
We began depreciating two recently completed lignite-fueled generation units in the fourth quarter 2009.
Assets related to capitalized leases included above totaled $167 million at both December 31, 2009 and 2008, net of accumulated depreciation.
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Asset Retirement Obligations
These liabilities primarily relate to nuclear generation plant decommissioning, land reclamation related to lignite mining, removal of lignite/coal-fueled plant ash treatment facilities and generation plant asbestos removal and disposal costs. There is no earnings impact with respect to the recognition of the asset retirement costs for nuclear decommissioning, as all costs are recoverable through the regulatory process as part of Oncor’s rates.
The following table summarizes the changes to the asset retirement liability, reported in other noncurrent liabilities and deferred credits in the balance sheet, during the years ended December 31, 2009 and 2008:
Asset retirement liability at January 1, 2008 | $ | 773 | ||
Additions: | ||||
Accretion | 48 | |||
Incremental mining reclamation costs | 59 | |||
Reductions: | ||||
Payments, essentially all mining reclamation | (21 | ) | ||
Asset retirement liability at December 31, 2008 | $ | 859 | ||
Additions: | ||||
Accretion | 59 | |||
Incremental mining reclamation costs | 59 | |||
Reductions: | ||||
Payments, essentially all mining reclamation | (29 | ) | ||
Asset retirement liability at December 31, 2009 | $ | 948 | ||
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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 Recovery/Amortization Period as of December 31, 2009 | Carrying Amount | |||||||
| December 31, 2009 | December 31, 2008 | |||||||
Regulatory assets: | ||||||||
Generation-related regulatory assets securitized by transition bonds (a) | 7 years | $ | 759 | $ | 865 | |||
Employee retirement costs | 5 years | 80 | — | |||||
Employee retirement costs to be reviewed (b)(c) | To be determined | 41 | 100 | |||||
Employee retirement liability (a)(c)(d) | To be determined | 768 | 559 | |||||
Self-insurance reserve (primarily storm recovery costs) — net | 7 years | 137 | — | |||||
Self-insurance reserve to be reviewed (b)(c) | To be determined | 106 | 214 | |||||
Nuclear decommissioning cost under-recovery (a)(c)(e) | Not applicable | 85 | 127 | |||||
Securities reacquisition costs (pre-industry restructure) | 8 years | 62 | 68 | |||||
Securities reacquisition costs (post-industry restructure) | Terms of related debt | 27 | 29 | |||||
Recoverable amounts for/in lieu of deferred income taxes — net | Life of related asset or liability | 68 | 77 | |||||
Rate case expenses (f) | Largely 3 years | 9 | 10 | |||||
Rate case expenses to be reviewed (b)(c) | To be determined | 1 | — | |||||
Advanced meter customer education costs | 10 years | 4 | 2 | |||||
Deferred conventional meter depreciation | 10 years | 14 | — | |||||
Energy efficiency performance bonus | 1 year | 9 | — | |||||
Business restructuring costs (g) | Not applicable | — | 20 | |||||
Total regulatory assets | 2,170 | 2,071 | ||||||
Regulatory liabilities: | ||||||||
Committed spending for demand-side management initiatives (a) | 3 years | 78 | 96 | |||||
Deferred advanced metering system revenues | 10 years | 57 | — | |||||
Investment tax credit and protected excess deferred taxes | Various | 44 | 49 | |||||
Over-collection of securitization (transition) bond revenues (a) | 7 years | 27 | 28 | |||||
Other regulatory liabilities (a) | Various | 5 | 6 | |||||
Total regulatory liabilities | 211 | 179 | ||||||
Net regulatory asset | $ | 1,959 | $ | 1,892 | ||||
| (a) | Not earning a return in the regulatory rate-setting process. |
| (b) | Costs incurred since the period covered under the last rate review. |
| (c) | Recovery is specifically authorized by statute, subject to reasonableness review by the PUCT. |
| (d) | Represents unfunded liabilities recorded in accordance with pension and OPEB accounting standards. |
| (e) | Offset by an intercompany payable to TCEH. |
| (f) | Rate case expenses totaling $4 million were disallowed by the PUCT and written off in the third quarter of 2009. |
| (g) | All previously recorded business restructuring costs were disallowed by the PUCT and written off in the third quarter of 2009. |
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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. We account for the difference between the surcharge billings for advanced metering facilities and the allowed revenues under the surcharge provisions, which are based on expenditures and an allowed return, as a regulatory asset or liability. Such differences arise principally as a result of timing of expenditures. As indicated in the table above, the regulatory liability at December 31, 2009 totaled $57 million.
See Note 6 for discussion of effects on regulatory assets and liabilities of the stipulation approved by the PUCT and Note 19 for additional information regarding nuclear decommissioning cost recovery.
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Other Noncurrent Liabilities and Deferred Credits
The balance of other noncurrent liabilities and deferred credits consists of the following:
| Successor | ||||||
| December 31, 2009 | December 31, 2008 | |||||
Uncertain tax positions (including accrued interest) (Note 8) | $ | 1,999 | $ | 1,780 | ||
Retirement plan and other employee benefits | 1,711 | 1,451 | ||||
Asset retirement obligations | 948 | 859 | ||||
Unfavorable purchase and sales contracts | 700 | 727 | ||||
Liabilities related to subsidiary tax sharing agreement | 321 | 299 | ||||
Other | 87 | 89 | ||||
Total other noncurrent liabilities and deferred credits | $ | 5,766 | $ | 5,205 | ||
Unfavorable Purchase and Sales Contracts — Unfavorable purchase and sales contracts primarily represent the extent to which contracts on a net basis were unfavorable to market prices as of the date of the Merger. These are contracts for which: (i) TCEH has made the “normal” purchase or sale election allowed or (ii) the contract did not meet the definition of a derivative under accounting standards related to derivative instruments and hedging transactions. Under purchase accounting, TCEH recorded the value as of October 10, 2007 as a deferred credit. Amortization of the deferred credit related to unfavorable contracts is primarily on a straight-line basis, which approximates the economic realization, and is recorded as revenues or a reduction of purchased power costs as appropriate. The amortization amount totaled $27 million and $30 million in 2009 and 2008, respectively, and $5 million in the 2007 Successor period. Favorable purchase and sales contracts are recorded as intangible assets (see Note 3).
The estimated amortization of unfavorable purchase and sales contracts for each of the next five fiscal years is as follows:
Year | Amount | ||
2010 | $ | 27 | |
2011 | 27 | ||
2012 | 27 | ||
2013 | 26 | ||
2014 | 25 | ||
Liabilities Related to Subsidiary Tax Sharing Agreement— Amount represents the previously recorded net deferred tax liabilities of Oncor related to the noncontrolling interests. Upon the sale of noncontrolling interests in Oncor (see Note 15), Oncor became a partnership for US federal income tax purposes, and the temporary differences which gave rise to the deferred taxes will, over time, become taxable to the noncontrolling interests. Under a tax sharing agreement among Oncor and its equity holders, Oncor reimburses the equity holders for federal income taxes as the partnership earnings become taxable to such holders. Accordingly, as the temporary differences become taxable, the equity holders will be reimbursed by Oncor. In the unlikely event such amounts are not reimbursed under the tax sharing agreement, it is probable they would be refunded to rate payers. The net changes in the liability for the year ended December 31, 2009 totaling $22 million reflected changes in temporary differences.
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Supplemental Cash Flow Information
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Cash payments (receipts) related to continuing operations: | ||||||||||||||||||
Interest paid (a) | $ | 2,972 | $ | 3,495 | $ | 496 | $ | 674 | ||||||||||
Capitalized interest | (277 | ) | (311 | ) | (59 | ) | (80 | ) | ||||||||||
Interest paid (net of capitalized interest) (a) | 2,695 | 3,184 | 437 | 594 | ||||||||||||||
Income taxes | (42 | ) | (204 | ) | — | 271 | ||||||||||||
Noncash investing and financing activities: | ||||||||||||||||||
Debt exchange transaction (Note 12) | (101 | ) | — | — | — | |||||||||||||
Below market values of power sales agreements (b) | — | — | — | 264 | ||||||||||||||
Noncash construction expenditures (c) | 197 | 183 | 211 | 210 | ||||||||||||||
Promissory note issued in conjunction with acquisition of mining-related assets | — | — | — | 65 | ||||||||||||||
Capital leases | 15 | 16 | — | 52 | ||||||||||||||
Noncash capital contribution from Texas Holdings | — | — | 23 | — | ||||||||||||||
| (a) | Net of interest received on interest rate swaps. |
| (b) | Multi-year power sales agreement entered into with Alcoa Inc. and recorded as part of the construction work-in-process asset balance for the Sandow 5 coal-fueled generation unit. |
| (c) | Represents end-of-period accruals. |
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| 26. | SUPPLEMENTAL GUARANTOR CONDENSED FINANCIAL INFORMATION |
In 2007, EFH Corp. issued $2.0 billion EFH Corp. 10.875% Notes and $2.5 billion EFH Corp. Toggle Notes (collectively, the EFH Corp. Senior Notes). In May 2009 and November 2009, EFH Corp. issued an additional $150 million and $159 million, respectively, of the EFH Corp. Toggle Notes. In November 2009, EFH Corp. issued $115 million EFH Corp. 9.75% Notes in exchange for certain outstanding debt securities (see Note 12). The EFH Corp. Senior Notes and 9.75% Notes are unconditionally guaranteed by EFC Holdings and Intermediate Holding, 100% owned subsidiaries of EFH Corp. (collectively, the Guarantors) on an unsecured basis except for the Intermediate Holding guarantee of the EFH Corp. 9.75% Notes, which is secured by a pledge of all membership interests and other investments Intermediate Holding owns or holds in Oncor Holdings or any of Oncor Holdings’ subsidiaries as described in Note 12. The guarantees issued by the Guarantors are full and unconditional, joint and several guarantees of the EFH Corp. Senior Notes and 9.75% Notes. The guarantees by EFC Holdings and the guarantee of the EFH Corp. Senior Notes by Intermediate Holding rank equally with any senior unsecured indebtedness of the Guarantors and rank effectively junior to all of the secured indebtedness of the Guarantors to the extent of the assets securing that indebtedness. All other subsidiaries of EFH Corp., either direct or indirect, do not guarantee the EFH Corp. Senior Notes and 9.75% Notes (collectively, the Non-Guarantors). The indentures governing the EFH Corp. Senior Notes and 9.75% Notes contain certain restrictions, subject to certain exceptions, on EFH Corp.’s ability to pay dividends or make investments. See Note 12.
The following tables have been prepared in accordance with Regulation S-X Rule 3-10, “Financial Statements of Guarantors and Issuers of Guaranteed Securities Registered or Being Registered” in order to present the condensed consolidating statements of income and cash flows of EFH Corp. (the Parent/Issuer), the Guarantors and the Non-Guarantors for the years ended December 31, 2009 and 2008, the period from October 11, 2007 through December 31, 2007 and the period from January 1, 2007 through October 10, 2007 and the consolidating balance sheets as of December 31, 2009 and 2008 of the Parent/Issuer, the Guarantors and the Non-Guarantors. Investments in consolidated subsidiaries are accounted for under the equity method. The presentations reflect the application of SEC Staff Accounting Bulletin Topic 5-J, “Push Down Basis of Accounting Required in Certain Limited Circumstances”, including the effects of the push down of the $4.63 billion and $4.5 billion principal amount of EFH Corp. Senior Notes as of December 31, 2009 and 2008, respectively, and the $115 million principal amount of the EFH Corp. 9.75% Notes as of December 31, 2009 to the Guarantors (see Notes 12 and 13).
EFH Corp. (Parent) received dividends from its consolidated subsidiaries totaling $216 million, $329 million and $1.461 billion for the years ended December 31, 2009 and 2008 and the Predecessor period from January 1, 2007 through October 10, 2007, respectively. EFH Corp. also received a distribution of $1.253 billion indirectly from Oncor as discussed in Note 15. No dividends were received during the period from October 11, 2007 through December 31, 2007. See Note 14.
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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)
| Successor | ||||||||||||||||||||
| Parent/Issuer | Guarantors | Non-Guarantors | Eliminations | Consolidated | ||||||||||||||||
Operating revenues | $ | — | $ | — | $ | 9,546 | $ | — | $ | 9,546 | ||||||||||
Fuel, purchased power costs and delivery fees | — | — | (2,878 | ) | — | (2,878 | ) | |||||||||||||
Net gain from commodity hedging and trading activities | — | — | 1,736 | — | 1,736 | |||||||||||||||
Operating costs | — | — | (1,598 | ) | — | (1,598 | ) | |||||||||||||
Depreciation and amortization | — | — | (1,754 | ) | — | (1,754 | ) | |||||||||||||
Selling, general and administrative expenses | (123 | ) | — | (945 | ) | — | (1,068 | ) | ||||||||||||
Franchise and revenue-based taxes | — | — | (359 | ) | — | (359 | ) | |||||||||||||
Impairment of goodwill | — | — | (90 | ) | — | (90 | ) | |||||||||||||
Other income | 49 | — | 114 | 41 | 204 | |||||||||||||||
Other deductions | (6 | ) | — | (91 | ) | — | (97 | ) | ||||||||||||
Interest income | 235 | 5 | 149 | (344 | ) | 45 | ||||||||||||||
Interest expense and related charges | (981 | ) | (570 | ) | (2,258 | ) | 897 | (2,912 | ) | |||||||||||
Income (loss) from continuing operations before income taxes and equity earnings of subsidiaries | (826 | ) | (565 | ) | 1,572 | 594 | 775 | |||||||||||||
Income tax (expense) benefit | 268 | 188 | (622 | ) | (201 | ) | (367 | ) | ||||||||||||
Equity earnings of subsidiaries | 902 | 965 | — | (1,867 | ) | — | ||||||||||||||
Net income (loss) | 344 | 588 | 950 | (1,474 | ) | 408 | ||||||||||||||
Net income attributable to noncontrolling interests | — | — | (64 | ) | — | (64 | ) | |||||||||||||
Net income (loss) attributable to EFH Corp. | $ | 344 | $ | 588 | $ | 886 | $ | (1,474 | ) | $ | 344 | |||||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Income
For the Year Ended December 31, 2008
(millions of dollars)
| Successor | ||||||||||||||||||||
| Parent/Issuer | Guarantors | Non-Guarantors | Eliminations | Consolidated | ||||||||||||||||
Operating revenues | $ | — | $ | — | $ | 11,364 | $ | — | $ | 11,364 | ||||||||||
Fuel, purchased power costs and delivery fees | — | — | (4,595 | ) | — | (4,595 | ) | |||||||||||||
Net gain from commodity hedging and trading activities | — | — | 2,184 | — | 2,184 | |||||||||||||||
Operating costs | — | — | (1,503 | ) | — | (1,503 | ) | |||||||||||||
Depreciation and amortization | — | — | (1,610 | ) | — | (1,610 | ) | |||||||||||||
Selling, general and administrative expenses | (105 | ) | — | (852 | ) | — | (957 | ) | ||||||||||||
Franchise and revenue-based taxes | — | 1 | (364 | ) | — | (363 | ) | |||||||||||||
Impairment of goodwill | — | — | (8,860 | ) | — | (8,860 | ) | |||||||||||||
Other income | — | — | 80 | — | 80 | |||||||||||||||
Other deductions | (22 | ) | — | (1,279 | ) | — | (1,301 | ) | ||||||||||||
Interest income | 168 | 7 | 147 | (295 | ) | 27 | ||||||||||||||
Interest expense and related charges | (919 | ) | (537 | ) | (4,298 | ) | 819 | (4,935 | ) | |||||||||||
Income (loss) from continuing operations before income taxes and equity earnings of subsidiaries | (878 | ) | (529 | ) | (9,586 | ) | 524 | (10,469 | ) | |||||||||||
Income tax (expense) benefit | 291 | 180 | 176 | (176 | ) | 471 | ||||||||||||||
Equity earnings of subsidiaries | (9,251 | ) | (9,184 | ) | — | 18,435 | — | |||||||||||||
Net loss | (9,838 | ) | (9,533 | ) | (9,410 | ) | 18,783 | (9,998 | ) | |||||||||||
Net loss attributable to noncontrolling interests | — | — | 160 | — | 160 | |||||||||||||||
Net loss attributable to EFH Corp. | $ | (9,838 | ) | $ | (9,533 | ) | $ | (9,250 | ) | $ | 18,783 | $ | (9,838 | ) | ||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Income
For the Period from October 11, 2007 through December 31, 2007
(millions of dollars)
| Successor | ||||||||||||||||||||
| Parent/Issuer | Guarantors | Non-Guarantors | Eliminations | Consolidated | ||||||||||||||||
Operating revenues | $ | — | $ | — | $ | 1,994 | $ | — | $ | 1,994 | ||||||||||
Fuel, purchased power costs and delivery fees | — | — | (644 | ) | — | (644 | ) | |||||||||||||
Net loss from commodity hedging and trading activities | — | — | (1,492 | ) | — | (1,492 | ) | |||||||||||||
Operating costs | — | — | (306 | ) | — | (306 | ) | |||||||||||||
Depreciation and amortization | — | — | (416 | ) | 1 | (415 | ) | |||||||||||||
Selling, general and administrative expenses | (17 | ) | — | (198 | ) | (1 | ) | (216 | ) | |||||||||||
Franchise and revenue-based taxes | (1 | ) | — | (92 | ) | — | (93 | ) | ||||||||||||
Other income | — | — | 14 | — | 14 | |||||||||||||||
Other deductions | (54 | ) | — | (7 | ) | — | (61 | ) | ||||||||||||
Interest income | 54 | 6 | 32 | (68 | ) | 24 | ||||||||||||||
Interest expense and related charges | (234 | ) | (140 | ) | (670 | ) | 205 | (839 | ) | |||||||||||
Loss from continuing operations before income taxes and equity earnings of subsidiaries | (252 | ) | (134 | ) | (1,785 | ) | 137 | (2,034 | ) | |||||||||||
Income tax benefit | 53 | 28 | 637 | (45 | ) | 673 | ||||||||||||||
Equity earnings of subsidiaries | (1,161 | ) | (1,142 | ) | — | 2,303 | — | |||||||||||||
Loss from continuing operations | (1,360 | ) | (1,248 | ) | (1,148 | ) | 2,395 | (1,361 | ) | |||||||||||
Income from discontinued operations, net of tax effect | — | — | 1 | — | 1 | |||||||||||||||
Net loss attributable to EFH Corp. | $ | (1,360 | ) | $ | (1,248 | ) | $ | (1,147 | ) | $ | 2,395 | $ | (1,360 | ) | ||||||
212
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Income
For the Period from January 1, 2007 through October 10, 2007
(millions of dollars)
| Predecessor | ||||||||||||||||||||
| Parent/Issuer | Guarantors | Non-Guarantors | Eliminations | Consolidated | ||||||||||||||||
Operating revenues | $ | — | $ | — | $ | 8,044 | $ | — | $ | 8,044 | ||||||||||
Fuel, purchased power costs and delivery fees | — | — | (2,381 | ) | — | (2,381 | ) | |||||||||||||
Net loss from commodity hedging and trading activities | — | — | (554 | ) | — | (554 | ) | |||||||||||||
Operating costs | — | — | (1,107 | ) | — | (1,107 | ) | |||||||||||||
Depreciation and amortization | — | — | (634 | ) | — | (634 | ) | |||||||||||||
Selling, general and administrative expenses | (58 | ) | — | (633 | ) | — | (691 | ) | ||||||||||||
Franchise and revenue-based taxes | — | (1 | ) | (282 | ) | 1 | (282 | ) | ||||||||||||
Other income | 8 | 1 | 60 | — | 69 | |||||||||||||||
Other deductions | (108 | ) | — | (733 | ) | — | (841 | ) | ||||||||||||
Interest income | 133 | 210 | 368 | (655 | ) | 56 | ||||||||||||||
Interest expense and related charges | (566 | ) | (192 | ) | (567 | ) | 654 | (671 | ) | |||||||||||
Income (loss) from continuing operations before income taxes and equity earnings of subsidiaries | (591 | ) | 18 | 1,581 | — | 1,008 | ||||||||||||||
Income tax (expense) benefit | 235 | (2 | ) | (542 | ) | — | (309 | ) | ||||||||||||
Equity earnings of subsidiaries | 1,077 | 1,554 | — | (2,631 | ) | — | ||||||||||||||
Income from continuing operations | 721 | 1,570 | 1,039 | (2,631 | ) | 699 | ||||||||||||||
Income from discontinued operations, net of tax effect | 2 | — | 22 | — | 24 | |||||||||||||||
Net income attributable to EFH Corp. | $ | 723 | $ | 1,570 | $ | 1,061 | $ | (2,631 | ) | $ | 723 | |||||||||
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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 advances — affiliates | 425 | 15 | — | (440 | ) | — | ||||||||||||||
Other, net | 5 | — | (33 | ) | — | (28 | ) | |||||||||||||
Cash provided by (used in) financing activities | 426 | (208 | ) | 212 | (8 | ) | 422 | |||||||||||||
Cash flows — investing activities: | ||||||||||||||||||||
Capital expenditures and nuclear fuel purchases | — | — | (2,545 | ) | — | (2,545 | ) | |||||||||||||
Money market fund redemptions | — | — | 142 | — | 142 | |||||||||||||||
Investment posted with derivative counterparty | (400 | ) | — | — | — | (400 | ) | |||||||||||||
Net proceeds from sale of majority interest in natural gas gathering pipeline business | — | — | 40 | — | 40 | |||||||||||||||
Reduction of restricted cash related to letter of credit facility | — | — | 115 | — | 115 | |||||||||||||||
Proceeds from sale of environmental allowances and credits | — | — | 19 | — | 19 | |||||||||||||||
Purchases of environmental allowances and credits | — | — | (19 | ) | — | (19 | ) | |||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | — | — | 3,064 | — | 3,064 | |||||||||||||||
Investments in nuclear decommissioning trust fund securities | — | — | (3,080 | ) | — | (3,080 | ) | |||||||||||||
Change in advances — affiliates | — | — | (440 | ) | 440 | — | ||||||||||||||
Other, net | — | — | 31 | — | 31 | |||||||||||||||
Cash provided by (used in) investing activities | (400 | ) | — | (2,673 | ) | 440 | (2,633 | ) | ||||||||||||
Net change in cash and cash equivalents | (16 | ) | — | (484 | ) | — | (500 | ) | ||||||||||||
Cash and cash equivalents — beginning balance | 1,075 | — | 614 | — | 1,689 | |||||||||||||||
Cash and cash equivalents — ending balance | $ | 1,059 | $ | — | $ | 130 | $ | — | $ | 1,189 | ||||||||||
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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)
| Successor | ||||||||||||||||||||
| Parent/Issuer | Guarantors | Non-guarantors | Eliminations | Consolidated | ||||||||||||||||
Cash provided by (used in) operating activities | $ | (251 | ) | $ | (924 | ) | $ | 832 | $ | 1,848 | $ | 1,505 | ||||||||
Cash flows — financing activities: | ||||||||||||||||||||
Issuances of securities/long-term borrowings: | ||||||||||||||||||||
Long-term debt | — | — | 3,185 | — | 3,185 | |||||||||||||||
Common stock | 34 | — | — | — | 34 | |||||||||||||||
Retirements/repurchases of securities/long-term borrowings: | ||||||||||||||||||||
Long-term debt | (200 | ) | (7 | ) | (960 | ) | — | (1,167 | ) | |||||||||||
Common stock | (3 | ) | — | — | — | (3 | ) | |||||||||||||
Change in short-term borrowings | — | — | (481 | ) | — | (481 | ) | |||||||||||||
Proceeds from sale of noncontrolling interests, net of transaction costs | 1,253 | 1,253 | 1,253 | (2,506 | ) | 1,253 | ||||||||||||||
Cash dividends paid | — | (329 | ) | (329 | ) | 658 | — | |||||||||||||
Change in advances — affiliates | 205 | 7 | — | (212 | ) | — | ||||||||||||||
Other, net | — | — | 16 | — | 16 | |||||||||||||||
Cash provided by (used in) financing activities | 1,289 | 924 | 2,684 | (2,060 | ) | 2,837 | ||||||||||||||
Cash flows — investing activities: | ||||||||||||||||||||
Capital expenditures and nuclear fuel purchases | — | — | (2,978 | ) | — | (2,978 | ) | |||||||||||||
Investments held in money market fund | — | — | (142 | ) | — | (142 | ) | |||||||||||||
Proceeds from sale of environmental allowances and credits | — | — | 39 | — | 39 | |||||||||||||||
Purchases of environmental allowances and credits | — | — | (34 | ) | — | (34 | ) | |||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | — | — | 1,623 | — | 1,623 | |||||||||||||||
Investments in nuclear decommissioning trust fund securities | — | — | (1,639 | ) | — | (1,639 | ) | |||||||||||||
Change in advances — affiliates | — | — | (212 | ) | 212 | — | ||||||||||||||
Other, net | 5 | — | 192 | — | 197 | |||||||||||||||
Cash provided by (used in) investing activities | 5 | — | (3,151 | ) | 212 | (2,934 | ) | |||||||||||||
Net change in cash and cash equivalents | 1,043 | — | 365 | — | 1,408 | |||||||||||||||
Cash and cash equivalents — beginning balance | 32 | — | 249 | — | 281 | |||||||||||||||
Cash and cash equivalents — ending balance | $ | 1,075 | $ | — | $ | 614 | $ | — | $ | 1,689 | ||||||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
Period from October 11, 2007 through December 31, 2007
(millions of dollars)
| Successor | ||||||||||||||||||||
| Parent/Issuer | Guarantors | Non-Guarantors | Eliminations | Consolidated | ||||||||||||||||
Cash provided by (used in) operating activities of continuing operations | $ | 170 | $ | (311 | ) | $ | (309 | ) | $ | — | $ | (450 | ) | |||||||
Cash flows — financing activities: | ||||||||||||||||||||
Issuance of securities: | ||||||||||||||||||||
Equity financing from Sponsor Group | 8,236 | — | — | — | 8,236 | |||||||||||||||
Long-term debt | 9,000 | — | 33,732 | — | 42,732 | |||||||||||||||
Retirements/repurchases of long-term debt | (5,522 | ) | (4 | ) | (9,869 | ) | — | (15,395 | ) | |||||||||||
Change in short-term borrowings | — | — | (722 | ) | — | (722 | ) | |||||||||||||
Change in advances — affiliates | 33 | — | — | (33 | ) | — | ||||||||||||||
Contributions to parent | — | (21,000 | ) | (21,000 | ) | 42,000 | — | |||||||||||||
Other, net | (400 | ) | 1 | (587 | ) | — | (986 | ) | ||||||||||||
Cash provided by (used in) financing activities | 11,347 | (21,003 | ) | 1,554 | 41,967 | 33,865 | ||||||||||||||
Cash flows — investing activities: | ||||||||||||||||||||
Acquisition of EFH Corp. | (32,694 | ) | — | — | — | (32,694 | ) | |||||||||||||
Contribution from subsidiaries | 21,000 | 21,000 | — | (42,000 | ) | — | ||||||||||||||
Capital expenditures and nuclear fuel | (2 | ) | — | (705 | ) | — | (707 | ) | ||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | — | — | 831 | — | 831 | |||||||||||||||
Investments in nuclear decommissioning trust fund securities | — | — | (835 | ) | — | (835 | ) | |||||||||||||
Proceeds from letter of credit facility deposited with trustee | — | — | (1,250 | ) | — | (1,250 | ) | |||||||||||||
Change in advances — affiliates | — | 314 | (347 | ) | 33 | — | ||||||||||||||
Other, net | (3 | ) | — | 95 | — | 92 | ||||||||||||||
Cash provided by (used in) investing activities | (11,699 | ) | 21,314 | (2,211 | ) | (41,967 | ) | (34,563 | ) | |||||||||||
Cash flows — discontinued operations: | ||||||||||||||||||||
Operating activities | — | — | (7 | ) | — | (7 | ) | |||||||||||||
Financing activities | — | — | — | — | — | |||||||||||||||
Investing activities | — | — | — | — | — | |||||||||||||||
Cash used in discontinued operations | — | — | (7 | ) | — | (7 | ) | |||||||||||||
Net change in cash and equivalents | (182 | ) | — | (973 | ) | — | (1,155 | ) | ||||||||||||
Cash and cash equivalents — beginning balance | 214 | — | 1,222 | — | 1,436 | |||||||||||||||
Cash and cash equivalents — ending balance | $ | 32 | $ | — | $ | 249 | $ | — | $ | 281 | ||||||||||
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Statements of Cash Flows
Period from January 1, 2007 through October 10, 2007
(millions of dollars)
| Predecessor | ||||||||||||||||||||
| Parent/Issuer | Guarantors | Non-Guarantors | Eliminations | Consolidated | ||||||||||||||||
Cash provided by operating activities of continuing operations | $ | 1,129 | $ | 1,468 | $ | 2,590 | $ | (2,922 | ) | $ | 2,265 | |||||||||
Cash flows — financing activities: | ||||||||||||||||||||
Issuance of securities: | ||||||||||||||||||||
Long-term debt | — | — | 1,800 | — | 1,800 | |||||||||||||||
Common stock | 1 | — | — | — | 1 | |||||||||||||||
Retirements/repurchases of securities: | ||||||||||||||||||||
Long-term debt | (1 | ) | (13 | ) | (431 | ) | — | (445 | ) | |||||||||||
Common stock | (13 | ) | — | — | — | (13 | ) | |||||||||||||
Change in short-term borrowings | — | — | 949 | — | 949 | |||||||||||||||
Cash dividends paid | (788 | ) | (1,461 | ) | (1,461 | ) | 2,922 | (788 | ) | |||||||||||
Change in advances — affiliates | 50 | — | — | (50 | ) | — | ||||||||||||||
Other, net | (93 | ) | — | (17 | ) | — | (110 | ) | ||||||||||||
Cash provided by (used in) financing activities | (844 | ) | (1,474 | ) | 840 | 2,872 | 1,394 | |||||||||||||
Cash flows — investing activities: | ||||||||||||||||||||
Capital expenditures and nuclear fuel | (70 | ) | — | (2,447 | ) | — | (2,517 | ) | ||||||||||||
Proceeds from sales of nuclear decommissioning trust fund securities | — | — | 602 | — | 602 | |||||||||||||||
Investments in nuclear decommissioning trust fund securities | — | — | (614 | ) | — | (614 | ) | |||||||||||||
Change in advances — affiliates | — | 6 | (56 | ) | 50 | — | ||||||||||||||
Other, net | (1 | ) | — | 247 | — | 246 | ||||||||||||||
Cash provided by (used in) investing activities | (71 | ) | 6 | (2,268 | ) | 50 | (2,283 | ) | ||||||||||||
Cash flows — discontinued operations: | ||||||||||||||||||||
Operating activities | — | — | 35 | — | 35 | |||||||||||||||
Financing activities | — | — | — | — | — | |||||||||||||||
Investing activities | — | — | — | — | — | |||||||||||||||
Cash provided by discontinued operations | — | — | 35 | — | 35 | |||||||||||||||
Net change in cash and equivalents | 214 | — | 1,197 | — | 1,411 | |||||||||||||||
Cash and cash equivalents — beginning balance | — | — | 25 | — | 25 | |||||||||||||||
Cash and cash equivalents — ending balance | $ | 214 | $ | — | $ | 1,222 | $ | — | $ | 1,436 | ||||||||||
217
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
at 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 | 4,586 | 3,634 | 682 | (8,152 | ) | 750 | |||||||||||||
Property, plant and equipment — net | — | — | 30,108 | — | 30,108 | ||||||||||||||
Notes receivable from affiliates | 12 | — | 2,236 | (2,248 | ) | — | |||||||||||||
Goodwill | — | — | 14,316 | — | 14,316 | ||||||||||||||
Intangible assets — net | — | — | 2,876 | — | 2,876 | ||||||||||||||
Regulatory assets — net | — | — | 1,959 | — | 1,959 | ||||||||||||||
Commodity and other derivative contractual assets | — | — | 1,533 | — | 1,533 | ||||||||||||||
Accumulated deferred income taxes | 647 | 111 | — | (758 | ) | — | |||||||||||||
Unamortized debt issuance costs and other noncurrent assets | 108 | 99 | 733 | (95 | ) | 845 | |||||||||||||
Total assets | $ | 7,507 | $ | 3,856 | $ | 61,670 | $ | (13,371 | ) | $ | 59,662 | ||||||||
| LIABILITIES AND EQUITY | |||||||||||||||||||
Current liabilities: | |||||||||||||||||||
Short-term borrowings | $ | — | $ | — | $ | 1,569 | $ | — | $ | 1,569 | |||||||||
Advances from affiliates | — | — | 476 | (476 | ) | — | |||||||||||||
Long-term debt due currently | — | 8 | 409 | — | 417 | ||||||||||||||
Trade accounts payable | 4 | — | 892 | — | 896 | ||||||||||||||
Accounts payable to affiliates | 16 | 6 | — | (22 | ) | — | |||||||||||||
Notes payable to affiliates | 1,406 | 27 | 150 | (1,583 | ) | — | |||||||||||||
Commodity and other derivative contractual liabilities | 82 | — | 2,310 | — | 2,392 | ||||||||||||||
Margin deposits related to commodity positions | — | — | 520 | — | 520 | ||||||||||||||
Accumulated deferred income taxes | 9 | — | — | (9 | ) | — | |||||||||||||
Accrued interest | 119 | 93 | 408 | (94 | ) | 526 | |||||||||||||
Other current liabilities | 7 | — | 761 | (24 | ) | 744 | |||||||||||||
Total current liabilities | 1,643 | 134 | 7,495 | (2,208 | ) | 7,064 | |||||||||||||
Accumulated deferred income taxes | — | — | 6,764 | (633 | ) | 6,131 | |||||||||||||
Investment tax credits | — | — | 37 | — | 37 | ||||||||||||||
Commodity and other derivative contractual liabilities | — | — | 1,060 | — | 1,060 | ||||||||||||||
Notes or other liabilities due affiliates | 2,019 | — | 229 | (2,248 | ) | — | |||||||||||||
Long-term debt, less amounts due currently | 6,626 | 4,975 | 34,740 | (4,901 | ) | 41,440 | |||||||||||||
Other noncurrent liabilities and deferred credits | 466 | 3 | 5,297 | — | 5,766 | ||||||||||||||
Total liabilities | 10,754 | 5,112 | 55,622 | (9,990 | ) | 61,498 | |||||||||||||
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 | ||||||||
218
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ENERGY FUTURE HOLDINGS CORP. AND SUBSIDIARIES
Condensed Consolidating Balance Sheets
at December 31, 2008
(millions of dollars)
| Parent/Issuer | Guarantors | Non-Guarantors | Eliminations | Consolidated | |||||||||||||||
| ASSETS | |||||||||||||||||||
Current assets: | |||||||||||||||||||
Cash and cash equivalents | $ | 1,075 | $ | — | $ | 614 | $ | — | $ | 1,689 | �� | ||||||||
Investments held in money market fund | — | — | 142 | — | 142 | ||||||||||||||
Restricted cash | — | — | 55 | — | 55 | ||||||||||||||
Advances to affiliates | 403 | 7 | — | (410 | ) | — | |||||||||||||
Trade accounts receivable — net | 3 | — | 1,216 | — | 1,219 | ||||||||||||||
Income taxes receivable | — | — | 128 | (86 | ) | 42 | |||||||||||||
Accounts receivable from affiliates | — | — | 3 | (3 | ) | — | |||||||||||||
Notes receivable from affiliates | — | — | 633 | (633 | ) | — | |||||||||||||
Inventories | — | — | 426 | — | 426 | ||||||||||||||
Commodity and other derivative contractual assets | 143 | — | 2,391 | — | 2,534 | ||||||||||||||
Accumulated deferred income taxes | — | — | 80 | (36 | ) | 44 | |||||||||||||
Margin deposits related to commodity positions | — | — | 439 | — | 439 | ||||||||||||||
Other current assets | 6 | — | 159 | — | 165 | ||||||||||||||
Total current assets | 1,630 | 7 | 6,286 | (1,168 | ) | 6,755 | |||||||||||||
Restricted cash | — | — | 1,267 | — | 1,267 | ||||||||||||||
Investments | 3,758 | 2,652 | 579 | (6,344 | ) | 645 | |||||||||||||
Property, plant and equipment — net | — | — | 29,522 | — | 29,522 | ||||||||||||||
Notes receivable from affiliates | 12 | — | 2,273 | (2,285 | ) | — | |||||||||||||
Goodwill | — | — | 14,386 | — | 14,386 | ||||||||||||||
Intangible assets — net | — | — | 2,993 | — | 2,993 | ||||||||||||||
Regulatory assets — net | — | — | 1,892 | — | 1,892 | ||||||||||||||
Commodity and other derivative contractual assets | — | — | 962 | — | 962 | ||||||||||||||
Accumulated deferred income taxes | 575 | 6 | — | (581 | ) | — | |||||||||||||
Unamortized debt issuance costs and other noncurrent assets | 130 | 111 | 711 | (111 | ) | 841 | |||||||||||||
Total assets | $ | 6,105 | $ | 2,776 | $ | 60,871 | $ | (10,489 | ) | $ | 59,263 | ||||||||
| LIABILITIES AND EQUITY | |||||||||||||||||||
Current liabilities: | |||||||||||||||||||
Short-term borrowings | $ | — | $ | — | $ | 1,237 | $ | — | $ | 1,237 | |||||||||
Advances from affiliates | — | — | 410 | (410 | ) | — | |||||||||||||
Long-term debt due currently | 3 | 8 | 374 | — | 385 | ||||||||||||||
Trade accounts payable | 8 | — | 1,135 | — | 1,143 | ||||||||||||||
Accounts payable to affiliates | — | 3 | — | (3 | ) | — | |||||||||||||
Notes payable to affiliates | 585 | 13 | 35 | (633 | ) | — | |||||||||||||
Commodity and other derivative contractual liabilities | 178 | — | 2,730 | — | 2,908 | ||||||||||||||
Margin deposits related to commodity positions | — | — | 525 | — | 525 | ||||||||||||||
Accumulated deferred income taxes | 36 | — | — | (36 | ) | — | |||||||||||||
Accrued interest | 110 | 87 | 413 | (86 | ) | 524 | |||||||||||||
Other current liabilities | 111 | — | 587 | (86 | ) | 612 | |||||||||||||
Total current liabilities | 1,031 | 111 | 7,446 | (1,254 | ) | 7,334 | |||||||||||||
Accumulated deferred income taxes | — | — | 6,648 | (581 | ) | 6,067 | |||||||||||||
Investment tax credits | — | — | 42 | — | 42 | ||||||||||||||
Commodity and other derivative contractual liabilities | — | — | 2,095 | — | 2,095 | ||||||||||||||
Notes or other liabilities due affiliates | 2,019 | — | 266 | (2,285 | ) | — | |||||||||||||
Long-term debt, less amounts due currently | 6,340 | 4,597 | 34,401 | (4,500 | ) | 40,838 | |||||||||||||
Other noncurrent liabilities and deferred credits | 388 | 1 | 4,817 | (1 | ) | 5,205 | |||||||||||||
Total liabilities | 9,778 | 4,709 | 55,715 | (8,621 | ) | 61,581 | |||||||||||||
EFH Corp. shareholders’ equity | (3,673 | ) | (1,933 | ) | 3,801 | (1,868 | ) | (3,673 | ) | ||||||||||
Noncontrolling interests in subsidiaries | — | — | 1,355 | — | 1,355 | ||||||||||||||
Total equity | (3,673 | ) | (1,933 | ) | 5,156 | (1,868 | ) | (2,318 | ) | ||||||||||
Total liabilities and equity | $ | 6,105 | $ | 2,776 | $ | 60,871 | $ | (10,489 | ) | $ | 59,263 | ||||||||
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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, 2009. 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, 2009 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, 2009 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 18, 2010
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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, 2009 (successor) 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, 2009, based on the criteria established inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
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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, 2009 (successor) and for the year ended December 31, 2009 (successor) of EFH Corp. and our report dated February 18, 2010 expressed an unqualified opinion on those financial statements.
/s/ Deloitte & Touche LLP
Dallas, Texas
February 18, 2010
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| Item 9B. | OTHER INFORMATION |
On February 15, 2010, the Organization and Compensation Committee (O&C Committee) of the Board approved several changes to our Chief Executive Officer and President’s (John Young) compensation arrangements, including certain amendments to his employment agreement and his stock option agreement. Generally, these changes were made after considering relevant market compensation data and for retention purposes.
Pursuant to Mr. Young’s amended employment agreement, Mr. Young’s base salary was increased from $1,000,000 to $1,200,000, which increase will be effective retroactively to January 1, 2010, and Mr. Young was granted a new cash-based retention incentive award (Retention Award). Under the terms of the Retention Award, Mr. Young will be entitled to receive on September 30, 2012, to the extent Mr. Young remains employed by EFH Corp. on such date (with customary exceptions for death, disability and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 100% of the aggregate Executive Annual Incentive Plan award received by (or otherwise payable to) Mr. Young for fiscal years 2009, 2010 and 2011.
In addition, Mr. Young’s amended employment agreement provides that EFH Corp. will (i) purchase, on behalf of Mr. Young, a 10 year term life insurance policy in an insured amount equal to $10,000,000 and (ii) adopt a supplemental retirement plan for Mr. Young 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.
Pursuant to Mr. Young’s amended stock option agreement, Mr. Young received a grant of 3,000,000 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. Young’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. Young surrendered to EFH Corp. 1,500,000 unvested performance-related stock options that were granted to Mr. Young when he joined EFH Corp.
Also, in February 2010, the O&C Committee increased James A. Burke’s (President and Chief Executive of TXU Energy) base salary to $630,000. The increase took effect retroactively on January 1, 2010.
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| Item 10. | DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT |
Directors
The names of EFH Corp.’s directors and information about them, as furnished by the directors themselves, are set forth below:
Name | Age | Served As Director Since | Business Experience | |||
| Arcilia C. Acosta (1)(4) | 44 | 2008 | Arcilia C. Acosta has served as a Director of EFH Corp. since May 2008. During the last five years, Ms. Acosta’s principal occupation and employment has been serving as the CEO of CARCON Industries & Construction, L.L.C. (CARCON) and its subsidiaries. She is also the CEO and controlling principal of Southwestern Testing Laboratories, L.L.C. (STL). CARCON’s principal business is commercial, institutional and transportation construction. STL’s principal business is geotechnical engineering, construction materials testing and environmental consulting. Ms. Acosta is a former Chair of the State of Texas Hispanic chambers organization known as the Texas Association of Mexican American Chambers of Commerce (TAMACC) and the Greater Dallas Hispanic Chamber of Commerce. Ms. Acosta serves on the Board of Advisors for Compass Bank and the Board of Governors for the Dallas Foundation. | |||
| David Bonderman | 67 | 2007 | David Bonderman has served as a Director of EFH Corp. since October 2007. He is a founding partner of TPG Capital, L.P. (TPG). Before forming TPG in 1992, Mr. Bonderman was Chief Operating Officer of the Robert M. Bass Group (now doing business as Keystone Group L.P.) in Fort Worth, Texas. He serves on the boards of the following public companies: Armstrong World Industries, Inc., CoStar Group, Inc., Gemalto N.V., General Motors Company, Harrahs’s Entertainment, RyanAir Holdings PLC, for which he serves as Chairman of the Board, and Univision Communications, Inc. During the past five years, Mr. Bonderman also served on the boards of Burger King Holdings, Inc., Ducati Motor Holding S.P.A., Gemplus International S.A. (predecessor to Gemalto N.V.), IASIS Healthcare Corporation, Korea First Bank Ltd., Mobilcom AG, and Washington Mutual, Inc. | |||
| Donald L. Evans (2)(3)(4) | 63 | 2007 | Donald L. Evans has served as a Director and Non-Executive Chairman of EFH Corp. since October 2007. He was CEO of the Financial Services Forum from 2005 to 2007, after serving as the 34th secretary of the US Department of Commerce. Before serving as Secretary of Commerce, Mr. Evans was the former CEO of Tom Brown, Inc., a large independent energy company. He also previously served as a member and chairman of the Board of Regents of the University of Texas System. Mr. Evans is also a Senior Partner at Quintana Energy Partners, L.P. | |||
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Name | Age | Served As Director Since | Business Experience | |||
| Thomas D. Ferguson (3) | 56 | 2008 | Thomas D. Ferguson has served as a Director of EFH Corp. since December 2008. He is a Managing Director of Goldman, Sachs & Co., having joined the firm in 2003. Mr. Ferguson heads the asset management efforts for the merchant bank’s infrastructure investment activity worldwide. He currently serves on the boards of some of Goldman, Sachs & Co.’s largest infrastructure investments, including Associated British Ports, the largest port company in the UK; Carrix, one of the largest private container terminal operators in the world; and Red de Carreteras, a major toll road concessionaire in Mexico. Additional responsibilities at Goldman, Sachs & Co. include an 18 month stint as the CEO of National Golf/American Golf, one of the leading owner/operators of golf courses in the US for which he now serves as the company’s non-executive Chairman. | |||
| Frederick M. Goltz (2)(3) | 38 | 2007 | Frederick M. Goltz has served as a Director of EFH Corp. since October 2007. He has been with Kohlberg Kravis Roberts and Co., L.P. (KKR) for 14 years. Mr. Goltz has played a significant role in the development of many of the themes pursued by KKR in the energy space, including those related to integrated utilities, merchant generation, and oil and gas exploration and production. He now heads KKR’s newly created Mezzanine Fund headquartered in San Francisco. He is a director of EFC Holdings, TCEH, and Luminant. During the past five years, Mr. Goltz also served on the boards of Accuride Corp. and Texas Genco Holdings, Inc. | |||
| James R. Huffines (1)(3) | 58 | 2007 | James R. Huffines has served as a Director of EFH Corp. since October 2007. He is Chairman of the University of Texas System Board of Regents, after previously serving as Vice Chairman from November 2007 to April 2009 and Chairman from June 2004 to November 2007. He also is Chairman, Central and South Texas Region, of PlainsCapital Bank, Senior Executive Vice President of PlainsCapital Corporation, and a director of Andrew Harper Travel Publications, Inc. and PlainsCapital Bank. | |||
| Scott Lebovitz | 34 | 2007 | Scott Lebovitz has served as a Director of EFH Corp. since October 2007. He is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area. He joined Goldman, Sachs & Co. in 1997 and was promoted to Managing Director in 2007. Mr. Lebovitz serves on the boards of both public and private companies, including CVR Energy, Inc., EFC Holdings, TCEH, and Luminant. | |||
| Jeffrey Liaw | 33 | 2007 | Jeffrey Liaw has served as a Director of EFH Corp. since October 2007. He is active in TPG’s energy and industrial investing practice areas. Before joining TPG in 2005, he worked for Bain Capital in its industrials practice. Mr. Liaw serves on the boards of both public and private companies, including Graphic Packaging Holding Company and Oncor. | |||
| Marc S. Lipschultz (2)(4) | 41 | 2007 | Marc S. Lipschultz has served as a Director of EFH Corp. since October 2007. He joined KKR in 1995 and is the global head of KKR’s Energy and Infrastructure business. Mr. Lipschultz serves on KKR’s Management Committee and its Infrastructure Investment Committee. Currently, he is on the boards of Accel-KKR Company and Oncor. During the past five years, Mr. Lipschultz also served on the boards of Texas Genco Holdings, Inc. and The Boyds Collection, Ltd. | |||
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Name | Age | Served As Director Since | Business Experience | |||
| Michael MacDougall (2)(3) | 39 | 2007 | Michael MacDougall has served as a Director of EFH Corp. since October 2007. He is a partner of TPG. Prior to joining TPG in 2002, Mr. MacDougall was a vice president in the Principal Investment Area of the Merchant Banking Division of Goldman, Sachs & Co., where he focused on private equity and mezzanine investments. Mr. MacDougall serves on the board of directors of both public and private companies, including Graphic Packaging Holding Company, Kraton Performance Polymers Inc., Valerus Compression Services, L.P., EFC Holdings, TCEH, and Luminant. During the past five years, he also served on the board of Aleris International. Mr. MacDougall also serves as the Chairman of the Board of The Opportunity Network and is a member of the Board of the Dwight School Foundation and Islesboro Affordable Property. | |||
| Lyndon L. Olson, Jr. (3) | 62 | 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) | 39 | 2007 | Kenneth Pontarelli has served as a Director of EFH Corp. since October 2007. He is a Managing Director of Goldman, Sachs & Co. in its Principal Investment Area. He transferred to the Principal Investment Area in 1999 and was promoted to Managing Director in 2004. Mr. Pontarelli serves as a director of both public and private companies, including CCS, Inc., Cobalt International Energy, L.P., Expro International Group Ltd., CVR Energy, Inc., Kinder Morgan, Inc. and TXU Energy. | |||
| William K. Reilly | 70 | 2007 | William K. Reilly has served as a Director of EFH Corp. since October 2007. He is a Senior Advisor to TPG and a founding partner of Aqua International Partners, an investment group that invests in companies that serve the water and renewable energy sectors. Mr. Reilly previously served as the seventh Administrator of the EPA. Mr. Reilly is a director of the following public companies: E.I DuPont de Nemours and Company, Eden Springs, Ltd. of Israel, ConocoPhillips and Royal Caribbean International. During the past five years, he also served on the board of Ionics Inc. Before serving as EPA Administrator, Mr. Reilly was President of World Wildlife Fund and President of The Conservation Foundation. He previously served as Executive Director of the Rockefeller Task Force on Land Use and Urban Growth, a senior staff member of the President’s Council on Environmental Quality, and Associate Director of the Urban Policy Center and the National Urban Coalition. Mr. Reilly is Co-Chairman of the National Commission on Energy Policy. | |||
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Name | Age | Served As Director Since | Business Experience | |||
| Jonathan D. Smidt | 37 | 2007 | Jonathan D. Smidt has served as a Director of EFH Corp. since October 2007. He has been with KKR since 2000, where he is a member of the firm’s Energy and Natural Resources industry team. Currently, he is a director of Laureate Education Inc., East Resources Inc. and TXU Energy. | |||
| John F. Young (2)(3) | 53 | 2008 | John F. Young has served as a Director and President and Chief Executive of EFH Corp. since January 2008. Before joining EFH Corp., Mr. Young served in many leadership roles at Exelon from March 2003 to January 2008 including Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation; President of Exelon Generation; and President and Chief Operating Officer of Exelon Power. Prior to joining Exelon, Mr. Young was Senior Vice President of Sierra Pacific Resources Corporation. Mr. Young is also a director of Luminant. | |||
| Kneeland Youngblood (1) | 54 | 2007 | Kneeland Youngblood has served as a Director of EFH Corp. since October 2007. He is a founding partner of Pharos Capital Group, a private equity firm that focuses on providing growth and expansion capital to businesses in technology, business services, and health care services. Mr. Youngblood is a director of the following public companies: Starwood Hotels and Resorts Worldwide, Inc., Gap Inc. and Burger King Holdings, Inc. Mr. Youngblood is a member of the Council on Foreign Relations. | |||
| (1) | Member of Audit Committee. |
| (2) | Member of Executive Committee. |
| (3) | Member of Governance and Public Affairs Committee |
| (4) | Member of Organization and Compensation Committee |
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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 the Company. Pursuant to such agreement, Messrs. Goltz, Lipschultz and Smidt were appointed to the Board as a consequence of their relationships with Kohlberg Kravis Roberts & Co.; Messrs. Bonderman, Liaw and MacDougall were appointed to the Board as a consequence of their relationships with TPG Capital, L.P., and Messrs. Ferguson, Lebovitz and Pontarelli were appointed to the Board as a consequence of their relationships with GS Capital Partners.
When considering whether the Board’s directors and nominees have the experience, qualifications, attributes and skills, taken as a whole, to enable the Board to satisfy its oversight responsibilities effectively in light of EFH Corp.’s business and structure, the Board focused primarily on the information in each of the Board member’s or nominee’s biographical information set forth on the pages above. In addition, EFH Corp. believes that each of its directors possesses high ethical standards, acts with integrity, and exercises careful judgment. Each is committed to employing his/her skills and abilities in the long-term interests of EFH Corp and its stakeholders. Finally, our directors are knowledgeable and experienced in business, governmental, and civic endeavors, further qualifying them for service as members of the Board.
The Sponsor Directors possess experience in owning and managing privately held enterprises and are familiar with corporate finance and strategic business planning activities of highly-leveraged companies such as EFH Corp. Some of the Sponsor Directors also have experience advising and overseeing the operations of large industrial, manufacturing or retail companies similar to our businesses. Finally, several of the Sponsor Directors possess substantial expertise in advising and managing companies in segments of energy industry, including, among others, power generation, oil and gas, and energy infrastructure and transportation.
As a group and individually, the Non-Sponsor Directors possess extensive experience in governmental and civic endeavors and in the business community, in each case, in the markets where our businesses operate.
Mr. Young’s employment agreement provides that he will serve as a member of the Board during the time he is employed by the Company. Before joining the Company as President and Chief Executive Officer, he held various senior management positions at other companies in the energy industry over twenty years, including, most recently, his role as Executive Vice President of Finance and Markets and Chief Financial Officer of Exelon Corporation.
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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 currently serves as Co-Chairman of the National Commission on Energy Policy. Mr. Youngblood has served on numerous boards for large public companies, has extensive experience managing and advising companies in his capacity as a partner in a private equity firm (not affiliated with the Sponsor Group), is highly knowledgeable of federal and state political matters, and has served on the board of directors of the United States Enrichment Corporation, a company that contracts with the 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 | Date First Elected to Present Offices | Business Experience (Preceding Five Years) | ||||
| John F. Young | 53 | 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 | 41 | 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 | 41 | President and Chief Executive of Luminant | June 2008 | David A. Campbell was elected President and Chief Executive of Luminant in June 2008. Mr. Campbell was Executive Vice President and Chief Financial Officer of EFH Corp. from April 2007 to June 2008 having previously served as Acting Chief Financial Officer beginning in March 2006 and as Executive Vice President for Corporate Planning, Strategy & Risk when he joined the company in May 2004. | ||||
| Charles R. Enze | 56 | Executive Vice President and Chief Executive of Luminant Construction | September 2006 | Charles R. Enze was elected Executive Vice President and Chief Executive of Luminant Construction in September 2006. Prior to joining EFH Corp. in 2006, Mr. Enze was Vice President of Engineering and Projects for Shell International Exploration & Production. | ||||
| M. S. Greene | 64 | Vice Chairman of EFH Corp. | June 2008 | M. S. Greene was elected Vice Chairman of EFH Corp. in June 2008. Previously Mr. Greene held several other offices including President and Chief Executive of Luminant, Chairman of the Board, President and Chief Executive of TXU Power, Executive Vice President of TCEH, and Vice Chairman, Chief Executive and President of Oncor. | ||||
| Joel D. Kaplan | 40 | 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. | ||||
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Name of Officer | Age | Positions and Offices | Date First Elected to Present Offices | Business Experience (Preceding Five Years) | ||||
| Paul M. Keglevic | 56 | Executive Vice President and Chief Financial Officer of EFH Corp. | July 2008 | Paul M. Keglevic was elected Executive Vice President and Chief Financial Officer of EFH Corp. in July 2008. Before joining EFH Corp., he was an audit partner at PricewaterhouseCoopers. Mr. Keglevic was PricewaterhouseCoopers’ Utility Sector Leader from 2002 to 2008 and Clients and Sector Assurance Leader from 2007 to 2008. | ||||
| Richard J. Landy | 64 | Executive Vice President of EFH Corp. | February 2010 | Richard J. Landy was elected Executive Vice President of EFH Corp. in February 2010 and oversees human resources. Prior to joining EFH Corp., Mr. Landy was owner and consultant of Richard J. Landy, LLC from 2007 to 2009 and Senior Vice President of Exelon from 2002 to 2007. | ||||
| M. A. McFarland | 40 | Executive Vice President and Chief Commercial Officer of Luminant and Executive Vice President of EFH Corp. | July 2008 | M. A. McFarland was elected Executive Vice President and Chief Commercial Officer of Luminant and Executive Vice President of EFH Corp. in July 2008. Before joining Luminant, Mr. McFarland served as Senior Vice President of Mergers, Acquisitions and Divestitures and as a Vice President in the wholesale marketing and trading division power team at Exelon. | ||||
| Robert C. Walters | 51 | 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. | ||||
There is no family relationship between any of the above-named executive officers.
Audit Committee Financial Expert
The Board has determined that James R. Huffines is an “Audit Committee Financial Expert” as defined in Item 407(d)(5) of SEC Regulation S-K.
Code of Conduct
EFH Corp. maintains certain corporate governance documents on EFH Corp’s website 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. Young’s employment agreement provides that he will continue to serve as a member of the Board during the time he is employed by EFH Corp.
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 Discussion and Analysis
Compensation of the CEO
In determining the compensation of the CEO, the O&C Committee annually follows a thorough and detailed process. At the end of each year, the O&C Committee reviews a self-assessment prepared by the CEO regarding his performance and the performance of our businesses and meets (with and without the CEO) to evaluate and discuss his performance and the performance of our businesses.
In addition to conducting an annual review of the CEO’s performance, the O&C Committee periodically uses independent compensation consultants to assess the compensation of the CEO against a variety of market reference points and competitive data, including the compensation practices of a number of companies that we consider to comprise our peer group, size-adjusted energy services industry survey data and size-adjusted general industry survey data. While the O&C Committee tries to ensure that the bulk of the CEO’s compensation is directly linked to his performance and the performance of our businesses, the O&C Committee also seeks to set his compensation in the manner that is competitive for retention purposes. The last assessment of the CEO’s compensation was performed in late 2009 / early 2010, when the O&C Committee engaged Towers Watson to perform a competitive analysis of the CEO’s compensation. In January 2010, Towers Watson delivered its report to the O&C Committee, which report included market data for a peer group composed of the following companies:
| AES Corporation | Allegheny Energy, Inc. | Ameren Corp. | ||
| American Electric Power Co. Inc, | Calpine Corp. | Constellation Energy Group Inc. | ||
| Dominion Resources Inc. | Duke Energy Corp. | Edison International | ||
| Entergy Corp. | Exelon Corp. | FirstEnergy Corp. | ||
| FPL Group Inc. | Mirant Corp. | NRG Energy, Inc. | ||
| PPL Corp. | Progress Energy Inc. | Public Service Enterprise Group Inc. | ||
| RRI Energy Inc. | Southern Co. | Xcel Energy Inc. |
The data for CEO compensation of the peer group was developed at both the 50th and 75th percentiles of market in order to provide the O&C Committee with a broad market view and multiple benchmarks. The O&C Committee targets total direct compensation around the 75th percentile of the peer group.
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While the O&C Committee considers market reference points and competitive data in determining the appropriate compensation of the CEO (and the other executive officers), the O&C Committee also considers qualitative and subjective factors that are more specific to EFH Corp. in making such determinations. One such factor is the fact that EFH Corp. is a highly-leveraged, privately-owned company. In this regard, while executive officers of publicly traded energy companies, including those in our peer group, are typically granted smaller long-term equity incentive awards on an annual basis, our executive officers received one-time, up front grants of long-term equity incentive awards intended to cover a multi-year period. Extended periods of economic strength or weakness generally has less affect on the cumulative value of annual awards as compared to one-time, up front awards because the annual awards are typically granted at fair market value over time. Accordingly, one-time, up front awards are typically riskier than annual awards.
After a comprehensive review of the CEO’s performance and the performance of our businesses in 2009, and taking into consideration the Towers Watson report, the economic dislocation occurring over the last 18 months and other qualitative and subjective factors as described above, the O&C Committee approved several changes to the compensation arrangement for the CEO in February 2010. The O&C Committee made these changes to provide incentives for retention and performance and to maintain a strong alignment between the CEO and our shareholders. We believe these changes are consistent with our compensation philosophy as described below.
Compensation of Other Executive Officers
In determining whether to make any adjustments to the compensation of any of our executive officers (other than the CEO), the O&C Committee seeks the input of the CEO. At the end of each year, the CEO reviews a self-assessment prepared by each of these executive officers and assesses the executive officer’s performance against business unit and individual goals and objectives. The O&C Committee and the CEO then review the CEO’s assessments and, in that context, the O&C Committee approves any adjustments to the compensation for each of these executive officers.
In addition to these annual reviews/assessments, the CEO periodically assesses the compensation of each of these executive officers. The last assessment of the compensation of the executive officers by the CEO was performed in the second half of 2009. Following that assessment, and taking into consideration the economic dislocation occurring over the last 18 months and other qualitative and subjective factors as described above, the CEO suggested several changes to the compensation arrangements for certain of our executive officers in order to provide incentives for retention and performance and to maintain alignment between our executive officers and shareholders. These changes, which are described in more detail below, were approved by the O&C Committee in October 2009 with respect to such executive officers, including each of Messrs. Keglevic, Campbell, Walters and Burke. We believe these changes are consistent with our compensation philosophy as described below.
Compensation Philosophy
We have a pay-for-performance compensation philosophy, which places an emphasis on pay-at-risk. In other words, a significant portion of an executive officer’s compensation is comprised of variable, at-risk incentive compensation. Our compensation program is intended to compensate executive officers appropriately for their contribution to the attainment of our financial, operational and strategic objectives. In addition, we believe it is important to retain our executive officers and strongly align their interests with EFH Corp.’s shareholders by emphasizing long-term incentive compensation, including equity-based compensation.
To achieve our compensation philosophy, we believe that:
| • | compensation plans should balance both long-term and short-term objectives; |
| • | the overall compensation program should emphasize variable compensation elements that have a direct link to overall corporate performance and shareholder value, and |
| • | an executive officer’s individual compensation level should be based upon an evaluation of the financial and operational performance of that executive officer’s business unit as well as the executive officer’s individual performance. |
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We believe our compensation philosophy supports our businesses by:
| • | aligning performance measures with our business objectives to drive the financial and operational performance of EFH Corp. and its business units; |
| • | rewarding business unit and individual performance by providing compensation levels consistent with the level of contribution and degree of accountability; |
| • | attracting and retaining the best performers, and |
| • | strengthening the correlation between the long-term interests of our executive officers and shareholders. |
Elements of Compensation
The material elements of our executive compensation program are:
| • | a base salary; |
| • | the opportunity to earn an annual performance-based cash bonus based on the achievement of specific corporate, business unit and individual performance goals, and |
| • | long-term incentive awards, primarily in the form of (i) long-term cash incentive awards and (ii) options to purchase shares of EFH Corp.’s common stock (the “Stock Option Awards”) under our 2007 Stock Incentive Plan for Key Employees of EFH Corp. and Affiliates (the “2007 Stock Incentive Plan”). |
In addition, executive officers generally have the opportunity to participate in certain of our broad-based employee compensation plans, including our Thrift (401(k)) Plan, retirement plans and non-qualified benefit plans, and to receive certain perquisites.
Assessment of Compensation Elements
We design the majority of an executive officer’s compensation to be directly linked to corporate and business unit performance. For example, an executive officer’s annual performance-based cash bonus is primarily based on the achievement of certain corporate and business unit financial and operational targets (such as management EBITDA, cost management, generation output and customer satisfaction). In addition, the vesting of a portion of each executive officer’s Stock Option Awards is contingent upon the attainment of certain management EBITDA targets. We also try to ensure that our executive compensation program is competitive in order to reduce the risk of losing our executive officers.
The following is a detailed discussion of the principal compensation elements provided to our executive officers. More detail about each of the elements can be found in the compensation tables, including the footnotes to the tables, and the narrative discussion following certain of the tables.
Base Salary
Base salary should reward executive officers for the scope and complexity of their position and the level of responsibility required. We believe that a competitive level of base salary is required to attract and retain qualified talent.
The O&C Committee annually reviews base salaries and periodically uses independent compensation consultants to ensure the base salaries are market-competitive. The O&C Committee may also review an executive officer’s base salary from time to time during a year, including if the executive officer is given a promotion or if his responsibilities are significantly increased.
We want to ensure our cash compensation is competitive and sufficient to incent executive officers to remain with us, recognizing our high performance expectations across a broad set of operational, financial, customer service and community-oriented goals and objectives and the higher risk levels associated with being a significantly-leveraged company.
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In light of the significant market dislocation and uncertainty that began in late 2008 and continued into 2009, our Named Executive Officers’ base salaries for 2009 remained unchanged from 2008 levels. In October 2009, the O&C Committee approved an increase in the base salary, effective January 1, 2010, for each of the Named Executive Officers, with the exception of Messrs. Young and Burke. In February 2010, the O&C Committee approved an increase in the base salary of each of Messrs. Young and Burke, which increases took effect retroactively on January 1, 2010. These increases reflect, in part, that none of the Named Executive Officers received a salary increase for 2009. The following table indicates the Named Executive Officers’ base salaries for 2008, 2009 and 2010.
Name | Title | 2008 Base Salary | 2009 Base Salary | Approved 2010 Base Salary | |||||||
John F. Young | President and Chief Executive Officer of EFH Corp. | $ | 1,000,000 | $ | 1,000,000 | $ | 1,200,000 | ||||
Paul M. Keglevic | Executive Vice President and Chief Financial Officer of EFH Corp. | $ | 600,000 | $ | 600,000 | $ | 650,000 | ||||
David A. Campbell | Chief Executive Officer of Luminant | $ | 600,000 | $ | 600,000 | $ | 700,000 | ||||
Robert C. Walters | Executive Vice President and General Counsel of EFH Corp. | $ | 575,000 | $ | 575,000 | $ | 600,000 | ||||
James A. Burke | Chief Executive Officer of TXU Energy | $ | 600,000 | $ | 600,000 | $ | 630,000 | ||||
Rizwan Chand (1) | Former Executive Vice President - Human Resources of EFH Corp. | $ | 450,000 | $ | 450,000 | N/A | |||||
| (1) | Mr. Chand’s employment with EFH Corp. terminated in October 2009. |
Annual Performance-Based Cash Bonus - Executive Annual Incentive Plan
The Executive Annual Incentive Plan (“EAIP”) provides an annual performance-based cash bonus for the successful attainment of certain annual financial and operational performance targets that are established annually at each of the corporate and business unit levels by the O&C Committee. Under the terms of the EAIP, performance against these targets, which are generally set at challenging levels to incent high performance, drives bonus funding. Based on the level of attainment of these performance targets, an aggregate EAIP funding percentage amount for all participants is determined.
Our financial performance targets typically include “management” EBITDA, a non-GAAP financial measure. When the O&C Committee reviews management EBITDA for purposes of determining our performance against the applicable management EBITDA target, it includes our earnings before interest, taxes, depreciation and amortization plus transaction, management and/or similar fees paid to the Sponsor Group, together with such adjustments as the O&C Committee shall determine appropriate in its discretion after good faith consultation with the CEO and the Chief Financial Officer, including adjustments consistent with those included in the comparable definitions in 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 submitted. The O&C Committee has broad authority to make these or any other adjustments to EBITDA that it deems appropriate in connection with its evaluation and compensation of our executive officers. Management EBITDA is an internal measure used only for performance management purposes, and EFH Corp. does not intend for management EBITDA to be an alternative to any measure of financial performance presented in accordance with GAAP. Management EBITDA is not the same as Adjusted EBITDA, which is disclosed elsewhere in this Form 10-K and defined in the glossary to this Form 10-K.
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Financial and Operational Performance Targets
The following table provides a summary of the performance targets for Mr. Young, who had primary responsibility at EFH Corp.
Performance Targets – EFH Corp. | Weight | Performance(1) | Payout | ||||||
EFH Corp. Management EBITDA | 50 | % | 101 | % | 50 | % | |||
EFH Corp. Management EBITDA (excluding Oncor) | 10 | % | 119 | % | 12 | % | |||
Luminant Scorecard Multiplier (see below) | 10 | % | 119 | % | 12 | % | |||
TXU Energy Scorecard Multiplier (see below) | 10 | % | 141 | % | 14 | % | |||
EFH Corp. Total Spend | 10 | % | 121 | % | 12 | % | |||
EFH Business Services Cost | 10 | % | 130 | % | 13 | % | |||
Total | 100 | % | 113 | % | |||||
| (1) | Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%. |
The following table provides a summary of the performance targets for Messrs. Keglevic and Walters, who had primary responsibility at EFH Corp. and EFH Business Services.
Performance Targets – EFH Corp. / Services | Weight | Performance(1) | Payout | ||||||
EFH Corp. Management EBITDA (excluding Oncor) | 60 | % | 119 | % | 72 | % | |||
Luminant Scorecard Multiplier (see below) | 10 | % | 119 | % | 12 | % | |||
TXU Energy Scorecard Multiplier (see below) | 10 | % | 141 | % | 14 | % | |||
EFH Corp. Total Spend | 10 | % | 121 | % | 12 | % | |||
EFH Business Services Cost | 10 | % | 130 | % | 13 | % | |||
Total | 100 | % | 123 | % | |||||
| (2) | Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%. |
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The following table provides a summary of the performance targets for Mr. Campbell, who had primary responsibility at Luminant.
Performance Targets – Luminant | Weight | Performance(1) | Payout | ||||||
EFH Corp. Management EBITDA (excluding Oncor) | 25 | % | 119 | % | 30 | % | |||
Luminant Management EBITDA (excluding 3 new units) | 30 | % | 146 | % | 44 | % | |||
Luminant Baseload Generation (excluding 3 new units) | 18.75 | % | 89 | % | 17 | % | |||
Luminant O&M/SG&A/Capital Expenditures | 15 | % | 139 | % | 21 | % | |||
Luminant Fossil Fuel Costs | 7.5 | % | 75 | % | 5 | % | |||
Management EBITDA for 3 new units (excluding capital expenditures) | 3.75 | % | 56 | % | 2 | % | |||
Total | 100 | % | 119 | % | |||||
| (1) | Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%. |
The following table provides a summary of the performance targets for Mr. Burke, who had primary responsibility at TXU Energy.
Performance Targets – TXU Energy | Weight | Performance(1) | Payout | ||||||
EFH Corp. Management EBITDA (excluding Oncor) | 25 | % | 119 | % | 30 | % | |||
TXU Energy Management EBITDA | 26.25 | % | 200 | % | 53 | % | |||
Contribution Margin | 15 | % | 200 | % | 30 | % | |||
TXU Energy Total Costs | 15 | % | 59 | % | 9 | % | |||
Upgrades to Customer Care System (Project Spend, PUCT Complaints and Days Meter to Cash) | 11.25 | % | 29 | % | 3 | % | |||
Customer Satisfaction | 7.5 | % | 150 | % | 11 | % | |||
Total | 100 | % | 136 | % | |||||
| (1) | Performance payouts equal 100% if the target amount is achieved for a particular metric, 50% if the threshold amount is achieved and 200% if the superior amount is achieved. The actual performance payouts are interpolated between threshold and target or target and superior, as applicable, with a maximum performance payout for any particular metric being equal to 200%. |
Individual Performance Modifier
After approving the actual performance against the applicable targets under the plan, the O&C Committee and/or the CEO reviews the performance of each of our executive officers on an individual and comparative basis. Based on this review, which includes an analysis of both objective and subjective criteria, including the CEO’s recommendations (with respect to all executive officers other than himself), the O&C Committee approves an individual modifier for each executive officer. Under the terms of the EAIP for 2009, the individual performance modifier can range from an outstanding rating (200%) to an unacceptable rating (0%). In February 2010, the O&C Committee amended the EAIP to reduce the maximum individual performance modifier applicable for 2010 and beyond from 200% to 150%. To calculate an executive officer’s final performance-based cash bonus, the executive officer’s corporate/business unit payout percentages are multiplied by the executive officer’s target incentive level, which is computed as a percentage of annualized base salary, and then by the executive officer’s individual performance modifier.
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Actual Award
The following table provides a summary of the 2009 performance-based cash bonus for each Named Executive Officer (other than Mr. Chand) under the EAIP.
Name | Target (% of salary) | Target Award ($Value) | Actual Award | ||||||
John F. Young (1) | 100 | % | $ | 1,000,000 | $ | 1,469,000 | |||
Paul M. Keglevic (2) | 75 | % | $ | 450,000 | $ | 664,200 | |||
David A. Campbell (3) | 75 | % | $ | 450,000 | $ | 642,600 | |||
Robert C. Walters (4) | 75 | % | $ | 431,250 | $ | 610,000 | |||
James A. Burke (5)
| 75 | % | $ | 450,000 | $ | 856,800 | |||
| (1) | Mr. Young’s incentive award is based on the successful achievement of the financial performance targets for EFH Corp. and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier that increased his incentive award. In 2009, Mr. Young successfully led the company in a difficult year in which sales volumes and demand fell, wholesale power prices declined and the credit markets were at times inaccessible. Notwithstanding these difficulties, Mr. Young created value in many parts of the company’s businesses. In particular, Mr. Young led the company’s efforts in, among other things: improving operations and safety at our generation and mining operations; participating in the national debate on climate change, green energy and financial reforms; bringing online two new lignite-fueled generation units on time and budget; implementing substantial and lasting cost reductions; exceeding EFH Corp.’s planned EBITDA for 2009; and strengthening the company’s management team. Given these and other significant achievements, the O&C Committee approved an individual performance modifier that increased Mr. Young’s incentive award. |
| (2) | Mr. Keglevic’s incentive award is based on the successful achievement of the financial performance targets for EFH Corp. and EFH Business Services and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier that increased his incentive award. In 2009, Mr. Keglevic successfully implemented several new financial processes at EFH Corp. and its business units, including processes for understanding, managing and communicating the financial and operational performance of our businesses, managing the varied risks of our businesses and preserving effective liquidity levels. In addition, Mr. Keglevic led the company’s liquidity and liability management efforts, including the successful amendment to the TCEH Senior Secured Facilities. Given these significant accomplishments and other achievements (including his installation of a “drive for results” culture), the O&C Committee approved an individual performance modifier that increased Mr. Keglevic’s incentive award. |
| (3) | Mr. Campbell’s incentive award is based on the successful achievement of a financial performance target for EFH Corp. and the financial and operational performance targets for Luminant and an individual performance modifier that increased his incentive award. In 2009, Mr. Campbell strengthened the Luminant management team (including, among others, the designation of a new Chief Nuclear Officer and Chief Fossil Officer) while overseeing strong financial and operational results primarily at Luminant’s nuclear plant and in Luminant’s wholesale energy organization. Luminant’s baseload generation construction program also achieved several important milestones, including the substantial completion of the two new lignite-fueled units, at costs and time-to-build schedules that are in the top decile relative to recent industry benchmarks. In addition, under Mr. Campbell’s leadership, Luminant had a very strong year for safety, with substantially all of its recordable safety metrics being in the top quartile for its industry. Given these significant accomplishments and other achievements (including his focus on developing strategic business solutions and building a team-oriented culture), the O&C Committee approved an individual performance modifier that increased Mr. Campbell’s incentive award. |
| (4) | Mr. Walters’ incentive award is based on the successful achievement of the financial performance targets for EFH Corp. and EFH Business Services and the financial and operational performance targets for Luminant and TXU Energy and an individual performance modifier that increased his incentive award. In 2009, Mr. Walters successfully managed several significant legal issues of the company. In particular, Mr. Walters’ led the company’s efforts in (i) defending the challenges to the Oak Grove and Sandow 5 construction and operating permits, (ii) negotiating the termination and transition of the company’s outsourcing relationship with CapGemini Energy and (iii) settling a dispute with the PUCT regarding alleged market manipulation activities. In addition, Mr. Walters drove improvements in the financial performance of our real estate holdings. Given these significant accomplishments and other achievements (including his strategic contributions in the political and civic arena on a local, state and national level), the O&C Committee approved an individual performance modifier that increased Mr. Walters’ incentive award. |
| (5) | Mr. Burke’s incentive award is based on the successful achievement of a financial performance target for EFH Corp. and the financial and operational performance targets for TXU Energy and an individual performance modifier that increased his incentive award. In 2009, Mr. Burke strengthened the TXU Energy management team and performance-oriented culture to drive strong financial and operational results at TXU Energy. Among the operational results, Mr. Burke led the successful implementation of a new customer care system and successfully managed the transition of a number of functions previously performed by Capgemini Energy. Among the financial results, Mr. Burke was successful in driving improvement in retail margins, managing TXU Energy through a challenging economic environment and implementing overall customer satisfaction ratings. Given these significant accomplishments and other achievements (including his continued commitment to build a strong retail and customer-focused culture at TXU Energy), the O&C Committee approved an individual performance modifier that increased Mr. Burke’s incentive award. |
In October 2009, the O&C Committee approved an increase in the annual target award under the EAIP from 75% of base salary to 85% of base salary for Messrs. Keglevic, Campbell, Walters and Burke. These increases will be effective for the 2010 award period.
Long-Term Incentive Awards
Long-Term Cash Incentive
In October 2009, the O&C Committee approved the adoption of a new long-term cash incentive (the “LTI”), effective as of the date of adoption, to be included by amendment in the employment agreements of each of Messrs. Keglevic, Campbell, Walters and Burke. Under the terms of the LTI, each of Messrs. Keglevic, Campbell, Walters and Burke will be entitled to receive on September 30, 2012, to the extent such Named Executive Officer remains employed by EFH Corp. on such date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 75% of the aggregate EAIP award received by such executive officer for fiscal years 2009, 2010 and 2011.
In February 2010, the O&C Committee approved the adoption of an LTI to be included by amendment in the employment agreement of Mr. Young. Under the terms of the LTI, Mr. Young will be entitled to receive on September 30, 2012, to the extent Mr. Young remains employed by EFH Corp. on such date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 100% of the aggregate EAIP award received by Mr. Young for fiscal years 2009, 2010 and 2011.
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.
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Long-Term Equity Incentives
We believe it is important to strongly align the interests of our executive officers and shareholders through equity-based compensation. In December 2007, our Board approved and adopted our 2007 Stock Incentive Plan pursuant to which we grant Stock Option Awards to our executive officers. The purpose of the 2007 Stock Incentive Plan is to:
| • | promote our long-term financial interests and growth by attracting and retaining management and other personnel with the training, experience and ability to make a substantial contribution to our success; |
| • | motivate management and other personnel by means of growth-related incentives to achieve long-range goals, and |
| • | strengthen the correlation between the long-term interests of our shareholders and the interests of our executive officers through opportunities for stock (or stock-based) ownership in EFH Corp. |
The Stock Option Awards granted to our executive officers provide significant retentive value because a portion of these awards is time-based and vest over a five year period. In addition, we believe that the Stock Option Awards granted to our executive officers provide incentive to our executive officers to achieve top operational and financial performance because a portion of these Stock Option Awards is performance-based and only vests upon EFH Corp. achieving certain management EBITDA targets.
In February 2008, Mr. Young was granted 7,500,000 Stock Option Awards. In May 2008, Messrs. Campbell, Walters and Burke were granted 4,000,000, 2,000,000 and 2,450,000 Stock Option Awards, respectively. In December 2008, Mr. Keglevic was granted 2,500,000 Stock Option Awards. Each of these Stock Option Awards are set forth in the table below and are referred to as the “Original Stock Option Awards,” half of which were “Original Time Vested Options” and half of which were “Original Performance Vested Options”. The exercise price of the Original Stock Option Awards (the fair market value on the grant date) is $5.00.
Executive Officer | Original Time Vested Options | Original Performance Vested Options | Exercise Price | ||||
John Young | 3,750,000 | 3,750,000 | $ | 5.00 | |||
Paul Keglevic | 1,250,000 | 1,250,000 | $ | 5.00 | |||
David Campbell | 2,000,000 | 2,000,000 | $ | 5.00 | |||
Robert Walters | 1,000,000 | 1,000,000 | $ | 5.00 | |||
James Burke | 1,225,000 | 1,225,000 | $ | 5.00 | |||
In October 2009 (February 2010, with respect to Mr. Young), the O&C Committee approved the grant of new Stock Option Awards to the Named Executive Officers as set forth in the table below. The new Stock Option Awards are referred to as the “New Stock Option Awards,” a portion of which are “New Time Vested Options” and a portion of which are “New Cliff Vested Options.” In connection with these grants, each Named Executive Officer surrendered to EFH Corp. a portion of his Original Performance Vested Options. The exercise price of the New Stock Option Awards is $3.50.
Executive Officer | Surrendered Original Performance Vested Options | New Time Vested Options | New Cliff Vested Options | Exercise Price | |||||
John Young | 1,500,000 | 1,500,000 | 1,500,000 | $ $ | 5.00 3.50 | ||||
Paul Keglevic | 500,000 | 500,000 | 500,000 | $ $ | 5.00 3.50 | ||||
David Campbell | 800,000 | 800,000 | 800,000 | $ $ | 5.00 3.50 | ||||
Robert Walters | 400,000 | 400,000 | 400,000 | $ $ | 5.00 3.50 | ||||
James Burke | 490,000 | 200,000 | 490,000 | $ $ | 5.00 3.50 | ||||
Please refer to the outstanding Equity Awards at Fiscal Year-End—2009 table, including the footnotes thereto, for a summary of the outstanding Stock Option Awards held by each of the Named Executive Officers.
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The Stock Option Awards vest (subject to the executive officer continuing to be employed by EFH Corp.) as follows:
| • | Time Vested Options |
| • | The Original Time Vested Options and the New Time Vested Options vest in 20% increments on each of the first five anniversaries of September 30, 2007 and September 30, 2009, respectively. |
| • | The New Cliff Vested Options vest 100% on September 30, 2014. |
| • | Performance Vested Options |
| • | The Original Performance Vested Options vest in 20% increments on each of the first five anniversaries of December 31, 2007, subject to our achievement of the annual management EBITDA target for the given fiscal year (or certain cumulative performance targets) as detailed in the stock option agreements. |
In deciding whether to vest the Original Performance Vested Options, the O&C Committee considers EFH Corp.’s quantitative performance against certain management EBITDA targets. The method of calculating management EBITDA for purposes of vesting the Original Performance Vested Options is the same as the method for calculating management EBITDA for purposes of the EAIP, as described above. The O&C Committee also has broad discretion to consider other qualitative and quantitative criteria that it deems appropriate in connection with its decision to vest the Original Performance Vested Options.
Our management EBITDA for 2009 was less than the management EBITDA target of $5.569 billion set forth in the applicable stock option agreements with respect to 2009. While EFH Corp. did not meet the applicable management EBITDA target, which was originally established in 2007, it exceeded the management EBITDA target established by the O&C Committee in the beginning of 2009 for purposes of the EAIP. In addition, EFH Corp.’s actual SG&A for 2009 was less than the targeted amount of SG&A set by the O&C Committee. Given these achievements, as well as the successful attainment of most of the other annual financial and operational performance targets that were established by the O&C Committee at the beginning of 2009, the O&C Committee exercised its discretionary authority under the 2007 Stock Incentive Plan and approved the vesting of the 2009 Original Performance Vested Options.
In the future, we may make additional discretionary grants of stock options or other equity-based compensation to reward high performance or achievement.
Equity Investment
In addition to being granted Stock Option Awards, several of our Named Executive Officers (including Messrs. Young, Keglevic, Campbell and Burke) have an equity investment in EFH Corp. These investments have been made through a direct cash investment for shares of EFH Corp. common stock (Mr. Young) and/or through the receipt of restricted stock units (Mr. Young) or deferred shares of EFH Corp. common stock (Messrs. Keglevic, Campbell and Burke) (i) as a result of the executive officer foregoing the right to receive certain payments from EFH Corp., whether in respect of outstanding equity awards issued prior to the Merger or otherwise (Messrs. Campbell and Burke) or (ii) as consideration for compensation forfeited by the executive officer when he left his former employer to join EFH Corp. (Messrs. Young and Keglevic). We believe such investment strongly aligns the interests of our Named Executive Officers with the interests of our shareholders and provides increased incentive to our executive officers to maximize financial and operational performance because the value of their investment is dependant upon the success of EFH Corp. In addition, as we are a private company, the illiquid nature of the investment provides additional retentive value.
Other Elements of Compensation
General
Our executive officers generally have the opportunity to participate in certain of our broad-based employee compensation plans, including our Thrift (401(k)) Plan, retirement plans and non-qualified benefit plans. Please refer to the footnotes to the Summary Compensation table for a more detailed description of our Thrift Plan, the narrative that follows the Pension Benefits table for a more detailed description of our Retirement Plan and Supplemental Executive Retirement Plan and the footnotes to the Nonqualified Deferred Compensation table for a more detailed description of our Salary Deferral Program.
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Perquisites
We do not believe that a significant amount of perquisites fit within our compensation philosophy. Those perquisites that exist are intended to serve as part of a competitive total compensation program and to enhance our executive officers’ ability to conduct company business. These benefits include financial planning, a preventive physical health exam and reimbursement for certain spousal travel expenses. Expenditures for the perquisites outlined above are disclosed by individual in footnotes to the Summary Compensation Table.
The following is a summary of perquisites offered to our Named Executive Officers that are not available to all employees:
Executive Financial Planning:We pay for our executive officers to receive financial planning services. This service is intended to support them in managing their financial affairs, which we consider especially important given the high level of time commitment and performance expectation required of our executive officers. Furthermore, we believe that such service helps ensure greater accuracy and compliance with individual tax regulations by our executive officers.
Annual Executive Physical Health Exam:We pay for our executive officers to receive annual physical health exams. The health of our executive officers is important given the vital leadership role they play in directing and operating the company. Our executive officers are important assets of EFH Corp., and this benefit is designed to help ensure their health and long-term ability to serve our shareholders.
Spouse Travel Expenses:From time to time, we pay for an executive officer’s spouse to travel with the executive officer when taking a business trip.
Contingent Payments
We have entered into employment agreements with Messrs. Young, Keglevic, Campbell, Walters and Burke. Each of the employment agreements provides that certain payments and benefits will be paid upon the expiration or termination of the agreement under various circumstances, including termination without cause, resignation for good reason and termination of employment within a fixed period of time following a change in control. We believe these provisions are important in order to attract and retain the caliber of executive officers that our business requires and provide incentive for our executive officers to fully consider potential changes that are in our and our shareholders’ best interest, even if such changes would result in the executive officers’ termination of employment. For a description of the applicable provisions in the employment agreements of our Named Executive Officers see “Potential Payments upon Termination or Change in Control.”
Other
In February 2010, the O&C Committee approved certain other compensation arrangements for Mr. Young. For a discussion of these arrangements, please see Item 9B, entitled Other Information in this Form 10-K.
Accounting and Tax Considerations
Accounting Considerations
Under FASB ASC Topic 718, the total amount of compensation expense to be recorded for stock-based awards (e.g., Stock Option Awards granted under the 2007 Stock Incentive Plan) is based on the fair value of the award on the grant date. This fair value is then recorded as expense over the vesting period, with an offsetting increase in paid-in capital. The amount of compensation expense is not subsequently adjusted for changes in our share price, for the actual number of shares distributed, or for any other factors except for true-ups related to estimated forfeitures compared to actual forfeitures. The surrendered shares are considered modifications to the original awards and are treated as an exchange of the original award for a new award. The compensation expense related to the new award represents the incremental costs of the surrendered shares and is based on the new grant date fair value and is recognized over its new vesting period.
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Income Tax Considerations
Section 162(m) of the Code limits the tax deductibility by a publicly held company of compensation in excess of $1 million paid to the CEO or any other of its three most highly compensated executive officers other than the principal financial officer. Because EFH Corp. is a privately-held company, Section 162(m) will not limit the tax deductibility of any executive compensation for 2009.
The O&C Committee administers our compensation programs with the good faith intention of complying with Section 409A of the Code.
Organization and Compensation Committee Report
The O&C Committee has reviewed and discussed with management the Compensation Discussion and Analysis set forth in this Form 10-K. Based on this review and discussions, the committee recommended to the Board that the Compensation Discussion and Analysis be included in this Form 10-K.
Organization and Compensation Committee
Donald L. Evans, Chair
Arcilia C. Acosta
Marc S. Lipschultz
Kenneth Pontarelli
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Summary Compensation Table
The following table provides information for the fiscal years ended December 31, 2009, 2008 and 2007 regarding the aggregate compensation paid to our Named Executive Officers.
Name and Principal Position | Year | Salary ($) | Bonus ($) | Stock Awards ($) | Option Awards ($)(7) | Non-Equity Incentive Plan Compensation ($)(8) | Change in Pension Value and Non-qualified Deferred Compensation Earnings ($)(9) | All Other Compensation ($)(10) | Total ($) | |||||||||
John F. Young (1) | 2009 2008 2007 | 1,000,000 912,500 N/A | — — N/A | — 3,000,000 N/A | — 13,635,000 N/A | 1,469,000 1,418,000 N/A | — — N/A | 105,291 462,258 N/A | 2,574,291 19,427,758 N/A | |||||||||
Paul M. Keglevic (2) | 2009 2008 2007 | 600,000 293,182 N/A | 150,000 250,000 N/A | — 1,125,000 N/A | 1,325,000 6,442,500 N/A | 664,200 613,800 N/A | — — N/A | 73,320 88,508 N/A | 2,812,520 8,812,990 N/A | |||||||||
David A. Campbell (3) | 2009 2008 2007 | 600,000 545,500 382,000 | — 5,092,250 — | — 2,500,000 2,292,000 | 2,120,000 7,272,000 — | 642,600 625,950 300,481 | 68,861 22,779 14,667 | 15,020 3,395,878 2,342,814 | 3,446,481 19,454,357 5,331,962 | |||||||||
Robert C. Walters (4) | 2009 2008 2007 | 575,000 435,609 N/A | — 100,000 N/A | — — N/A | 1,060,000 3,636,000 N/A | 610,000 695,175 N/A | — — N/A | 81,562 44,249 N/A | 2,326,562 4,911,033 N/A | |||||||||
James A. Burke (5) | 2009 2008 2007 | 600,000 600,000 342,712 | — — — | — — 830,850 | 933,100 4,454,100 — | 856,800 473,918 274,050 | 55,931 25,501 9,864 | 23,885 639,136 978,189 | 2,469,716 6,192,655 2,435,665 | |||||||||
Rizwan Chand (6) | 2009 2008 2007 | 348,750 N/A N/A | — N/A N/A | — N/A N/A | — N/A N/A | — N/A N/A | 36,218 N/A N/A | 2,110,925 N/A N/A | 2,495,893 N/A N/A | |||||||||
| (1) | Mr. Young commenced employment with EFH Corp. in January 2008. The amounts for 2009 reported as “All Other Compensation” for Mr. Young represent (i) the costs of providing certain perquisites, including $9,728 for financial planning and $863 of taxable reimbursements partially related to his spouse’s travel and (ii) $14,700 and $80,000 for our matching contributions to the EFH Thrift Plan and the Salary Deferral Plan, respectively. |
| (2) | Mr. Keglevic commenced employment with EFH Corp. in July 2008. Mr. Keglevic’s employment agreement provides that we pay him a signing bonus equal to $550,000 as follows: (i) $250,000 payable in July 2008; (ii) $150,000 payable in July 2009 and (iii) $50,000 payable in July 2010, 2011 and 2012. The amount for 2009 reported as “Bonus” for Mr. Keglevic represents the 2009 portion of his signing bonus. The amounts for 2009 reported as “All Other Compensation” for Mr. Keglevic represent (i) the costs of providing certain perquisites, including $2,724 for an executive physical, $3,410 of taxable reimbursements primarily related to his spouse’s travel and $11,836 for moving expenses and (ii) $7,350 and $48,000 for our matching contributions to the EFH Thrift Plan and the Salary Deferral Plan, respectively. |
| (3) | The amount reported as “All Other Compensation” in 2009 for Mr. Campbell represents (i) $10,120 for financial planning and (ii) $4,900 for our matching contributions to the EFH Thrift Plan. The amount reported as “All Other Compensation” in 2008 for Mr. Campbell includes $3,319,963 for a tax gross-up payment that was made in 2009. The tax gross-up payment, which was not reported in the 2008 Summary Compensation Table, related to excise taxes due with respect to a January 2009 payment of $5,092,250 that was provided to Mr. Campbell as an inducement for entering into his employment agreement in 2008. The $5,092,250 was reported in the 2008 Summary Compensation Table under “Bonus,” and we believe the tax gross-up payment should be reported for the same calendar year as the related payment. |
| (4) | Mr. Walters commenced employment with EFH Corp. in March 2008. The amounts for 2009 reported as “All Other Compensation” for Mr. Walters represent (i) the costs of providing certain perquisites, including $16,800 for financial planning, $2,350 for an executive physical and $1,712 of taxable reimbursements primarily related to his spouse’s travel and (ii) $14,700 and $46,000 for our matching contributions to the EFH Thrift Plan and the Salary Deferral Plan, respectively. |
| (5) | The amounts for 2009 reported as “All Other Compensation” for Mr. Burke represent (i) the costs of providing certain perquisites, including $8,875 for financial planning, $2,350 for an executive physical and $660 of taxable reimbursements and (ii) $12,000 for our matching contributions to the EFH Thrift Plan. |
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| (6) | Mr. Chand’s employment terminated with EFH Corp. in October 2009. The amounts for 2009 reported as “All Other Compensation” for Mr. Chand represent (i) the costs of providing certain perquisites, including $8,875 for financial planning and $2,350 for an executive physical (ii) $14,700 for our matching contributions to the EFH Thrift Plan, (iii) $1,485,000 in cash severance due to him under the terms of his employment agreement, and (iv) $600,000 related to his deferred share agreement with EFH Corp. |
| (7) | The amounts reported as “Option Awards” represent the grant date fair value of Stock Option Awards granted in the fiscal year computed for the stock options awarded under the 2007 Stock Incentive Plan in accordance with FASB ASC Topic 718 and do not take into account estimated forfeitures. See table titled “Grants of Plan-Based Awards – 2009”. In February 2010, Mr. Young received certain new Stock Option Awards. The grant date fair value of those Stock Option Awards was $3,405,000. |
| (8) | The amounts in 2009 reported as “Non-Equity Incentive Plan Compensation” were earned by the executive officers in 2009 under the EAIP and are expected to be paid in March 2010. |
| (9) | The amounts in 2009 reported under “Change in Pension Value and Nonqualified Deferred Compensation Earnings” (i) include the aggregate increase in actuarial value of EFH Corp.’s Retirement Plan and Supplemental Retirement Plan and (ii) exclude amounts attributable to the portion of the vested amounts for Messrs. Young ($33,313), Keglevic ($44,409), Walters ($62,351) and Burke ($19,500) that were transferred from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan as of December 31, 2009. For a more detailed description of EFH Corp.’s retirement plans, including the transfers of certain assets and liabilities from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan, please refer to the narrative that follows the table titled “Pension Benefits”. There are no above market earnings for nonqualified deferred compensation that is deferred under the Salary Deferral Program. |
| (10) | As described above, “All Other Compensation” includes amounts associated with our matching contributions to the EFH Thrift Plan and Salary Deferral Plan. Our Thrift Plan allows participating employees to contribute a portion of their regular salary or wages to the plan. Under the Thrift Plan, EFH Corp. matches a portion of an employee’s contributions. This matching contribution is 100% of each Named Executive Officer’s contribution up to 6% of the named Executive Officer’s salary. All matching contributions are invested in Thrift Plan investments as directed by the participant. Please refer to the narrative that follows the Nonqualified Deferred Compensation table for a more detailed description of the Salary Deferral Program. |
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Grants of Plan-Based Awards – 2009
The following table sets forth information regarding grants of compensatory awards to our Named Executive Officers during the fiscal year ended December 31, 2009.
Name | Grant Date | Date of Board Action | Estimated Possible Payouts Under Non-Equity Incentive Plan Awards(1) | Estimated Future Payouts Under Equity Incentive Plan Awards | All Other Stock Awards: # Shares or Unit | All Other Option Awards: # of Securities Underlying Options (#)(2) | Exercise or Base Price of Option Awards ($/sh) | Grant Date Fair Value of Stock and Option Awards(3) | |||||||||||||||||
| Threshold ($) | Target ($) | Max. ($) | Threshold (#) | Target (#) | Max. (#) | ||||||||||||||||||||
John F. Young | 2/18/09 | 2/18/09 | 500,000 | 1,000,000 | 2,000,000 | ||||||||||||||||||||
Paul M. Keglevic | 2/18/09 12/17/09 | 2/18/09 10/29/09 | 225,000 | 450,000 | 900,000 | 1,000,000 | $ | 3.50 | 1,325,000 | ||||||||||||||||
David A. Campbell | 2/18/09 12/17/09 | 2/18/09 10/29/09 | 225,000 | 450,000 | 900,000 | 1,600,000 | $ | 3.50 | 2,120,000 | ||||||||||||||||
Robert C. Walters | 2/18/09 12/17/09 | 2/18/09 10/29/09 | 215,625 | 431,250 | 862,500 | 800,000 | $ | 3.50 | 1,060,000 | ||||||||||||||||
James A. Burke | 2/18/09 12/17/09 | 2/18/09 10/29/09 | 225,000 | 450,000 | 900,000 | 690,000 | $ | 3.50 | 933,100 | ||||||||||||||||
Rizwan Chand | — | — | — | — | — | — | — | — | |||||||||||||||||
| (1) | The amounts disclosed under the heading “Estimated Possible Payouts under Non-Equity Incentive Plan Awards” reflect the threshold, target and maximum amounts available under the EAIP for each executive officer and each executive officer’s employment agreement. The actual awards for the 2009 plan year are expected to be paid in March 2010 and are reported in the Summary Compensation Table under the heading “Non-Equity Incentive Plan Compensation” and described above under the section entitled “Annual Performance Bonus - EAIP”. |
| (2) | Represents grants of New Time Vested Options and New Cliff Vested Options under the 2007 Stock Incentive Plan, as described above under “Long-Term Incentive Awards.” |
| (3) | The amounts reported under “Grant Date Fair Value of Stock Award” represent the grant date fair value of stock options related to the 2009 Awards in accordance with FASB ASC Topic 718. |
For a discussion of the terms of the New Stock Option Awards granted to each Named Executive Officer (other than Mr. Chand) in connection with such Named Executive Officer surrendering a portion of his Original Performance Vested Options, please see “Long-Term Incentive Awards – Long-Term Equity Incentives.” For a discussion of certain material terms of the employment agreements with the Named Executive Officers, please see “Assessment of Compensation Elements” and “Potential Payments upon Termination or Change in Control.”
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Outstanding Equity Awards at Fiscal Year-End– 2009
| Option Awards | Stock Awards | ||||||||||||||||||
| # of Securities Underlying Unexercised Options | Equity Incentive Plan Awards: # of Securities Underlying Unexercised Unearned Options(4) | Option Exercise Price | Option Expiration Date | # of Shares or Units of Stock That Have Not Vested(5) | Market Value of Shares or Units of Stock That Have Not Vested | Equity Incentive Plan Awards: # of Unearned Shares, Units or Other Rights That Have Not Vested | Equity Incentive Plan Awards: Market Payout Value of Unearned Shares, Units or Rights That Have Not Vested | ||||||||||||
Name | Exercisable | Unexercisable | |||||||||||||||||
John F. Young (6) | 2,250,000 | 2,250,000 | (1) | 3,000,000 | 5.00 | 02/01/2018 | |||||||||||||
Paul M. Keglevic | 750,000 | 750,000 500,000 500,000 | (1) (2) (3) | 500,000 | 5.00 3.50 3.50 | 12/22/2018 12/17/2019 12/17/2019 | 225,000 | 787,500 | |||||||||||
David A. Campbell | 1,200,000 | 1,200,000 800,000 800,000 | (1) (2) (3) | 800,000 | 5.00 3.50 3.50 | 05/20/2018 12/17/2019 12/17/2019 | |||||||||||||
Robert C. Walters | 600,000 | 600,000 400,000 400,000 | (1) (2) (3) | 400,000 | 5.00 3.50 3.50 | 05/20/2018 12/17/2019 12/17/2019 | |||||||||||||
James A. Burke | 735,000 | 735,000 200,000 490,000 | (1) (2) (3) | 490,000 | 5.00 3.50 3.50 | 05/20/2018 12/17/2019 12/17/2019 | |||||||||||||
Rizwan Chand | 350,000 | 5.00 | 04/04/2010 | ||||||||||||||||
| (1) | These Original Time Vested Options are scheduled to become exercisable ratably in September 2010, 2011 and 2012 provided the Named Executive Officer has remained continuously employed by EFH Corp. through the applicable vesting date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”). |
| (2) | These New Time Vested Options are scheduled to become exercisable ratably in September 2010, 2011, 2012, 2013 and 2014 provided the Named Executive Officer has remained continuously employed by EFH Corp. through the applicable vesting date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”). |
| (3) | These New Cliff Vested Options are scheduled to become exercisable in September 2014 provided the Named Executive Officer has remained continuously employed by EFH Corp. through that date (with customary exceptions for death, disability, and leaving for “good reason” or termination without “cause”). |
| (4) | If we achieve certain performance targets, these Original Performance Vested Options are eligible to become exercisable as of the end of fiscal years 2010, 2011 and 2012. See “Long-Term Incentive Awards-Long-Term Equity Incentives” for a detailed description of the vesting schedule for the Original Performance Vested Options and the decision by the O&C Committee in February 2010 to approve the vesting of a portion of the Original Performance Vested Options. |
| (5) | This column reflects deferred shares described above under “Long-Term Incentive Awards-Equity Investment.” The deferred shares for Mr. Keglevic will vest and become nonforfeitable as to (i) 112,500 of the shares on the third anniversary of his employment (July 2011) and (ii) 112,500 of the shares on the fifth anniversary of his employment (July 2013). |
| (6) | In February 2010, Mr. Young surrendered 1,500,000 Original Performance Vested Options listed in the “Equity Incentive Plan Awards: # of Securities Underlying Unexercised Unearned Options” column, and in connection therewith received 1,500,000 New Time Vested options and 1,500,000 New Cliff Vested Options. |
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Options Exercised and Stock Vested – 2009
None of the Named Executive Officers exercised any of his vested Stock Option Awards in 2009. In addition, none of the Named Executive Officers owned any restricted or deferred shares of EFH Corp. common stock that vested in 2009.
Pension Benefits – 2009
The table set forth below illustrates present value on December 31, 2009 of each Named Executive Officer’s Retirement Plan benefit and benefits payable under the Supplemental Retirement Plan, based on their years of service and remuneration through December 31, 2009:
Name | Plan Name | Number of Years Credited Service (#) | PV of Accumulated Benefit ($) | Payments During Last Fiscal Year ($) | ||||
John F. Young | Retirement Plan Supplemental Retirement Plan | N/A N/A | 33,313 N/A | — N/A | ||||
Paul M. Keglevic | Retirement Plan Supplemental Retirement Plan | N/A N/A | 44,409 N/A | — N/A | ||||
David A. Campbell (1) | Retirement Plan Supplemental Retirement Plan | 4.5833 7.5000 | 109,838 34,912 | — — | ||||
Robert C. Walters | Retirement Plan Supplemental Retirement Plan | N/A N/A | 62,351 N/A | — N/A | ||||
James A. Burke | Retirement Plan Supplemental Retirement Plan | 4.1667 4.1667 | 99,396 29,397 | — — | ||||
Rizwan Chand | Retirement Plan Supplemental Retirement Plan | 3.3333 3.3333 | 34,180 41,752 | — — |
EFH Corp. and its participating subsidiaries maintain the Retirement Plan, which is intended to be qualified under applicable provisions of the Code and covered by ERISA. The Retirement Plan contains both a traditional defined benefit component and a cash balance component. Only employees hired before January 1, 2002 may participate in the traditional defined benefit component. Accordingly, none of the Named Executive Officers participates in the traditional defined benefit component. Employees hired after January 1, 2002 and before October 1, 2007 are eligible to participate in the cash balance component. In addition, effective December 31, 2009, certain assets and liabilities under the Salary Deferral Program and the Supplemental Retirement Plan were transferred to the cash balance component of the Retirement Plan. Accordingly, Messrs. Campbell and Burke have participated and may continue to participate in the cash balance component of the Retirement Plan; and Messrs. Young, Keglevic and Walters participate in the cash balance component of the Retirement Plan solely with respect to amounts that were transferred from the Salary Deferral Program.
Under the cash balance component of the Retirement Plan, hypothetical accounts are established for participants and credited with monthly contribution credits equal to a percentage of the participant’s compensation (3.5%, 4.5%, 5.5% or 6.5% depending on the participant’s combined age and years of accredited service), contribution credits equal to the amounts transferred from the Salary Deferral Program and/or the Supplemental Retirement Plan effective as of December 31, 2009 and interest credits on all of such amounts based on the average yield of the 30-year Treasury bond for the 12 months ending November 30 of the prior year.
The Supplemental Retirement Plan provides for the payment of retirement benefits, which would otherwise be limited by the Code or the definition of earnings under the Retirement Plan. Under the Supplemental Retirement Plan, retirement benefits under the cash balance component are calculated in accordance with the same formula used under the Retirement Plan. Participation in EFH Corp.’s Supplemental Retirement Plan has been limited to employees of all of its businesses other than Oncor, who were employed by EFH Corp. (or its participating subsidiaries) on or before October 1, 2007. Accordingly, Messrs. Campbell and Burke participate in the Supplemental Retirement Plan, and Messrs. Young, Keglevic and Walters are not eligible to participate in the Supplemental Retirement Plan.
Benefits accrued under the Supplemental Retirement Plan after December 31, 2004, are subject to Section 409A of the Code. Accordingly, certain provisions of the Supplemental Retirement Plan have been modified in order to comply with the requirements of Section 409A and related guidance.
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The present value of the accumulated benefit for the Retirement Plan (the cash balance component) was calculated as the value of their cash balance account projected to age 65 at an assumed growth rate of 4.75% and then discounted back to December 31, 2009 at 5.90%. No mortality or turnover assumptions were applied.
Nonqualified Deferred Compensation – 2009(1)
The following table sets forth information regarding plans that provide for the deferral of the Named Executive Officers’ compensation on a basis that is not tax-qualified for the fiscal year ended December 31, 2009:
Name | Executive Contributions in Last FY ($) | Registrant Contributions in Last FY ($)(2) | Aggregate Earnings in Last FY ($) | Aggregate Withdrawals/ Distributions($)(3) | Aggregate Balance at Last FYE ($)(4) | ||||||
John F. Young | 80,000 | 80,000 | 56,561 | — | 281,715 | ||||||
Paul M. Keglevic | 48,000 | 48,000 | 72 | — | 87,703 | ||||||
David A. Campbell | — | — | 48,558 | 195,891 | |||||||
Robert C. Walters | 46,000 | 46,000 | 32,367 | — | 103,402 | ||||||
James A. Burke | — | — | 86,658 | — | 233,262 | ||||||
Rizwan Chand | — | — | 28,960 | (116,068 | ) | — | |||||
| (1) | The amounts reported in the Nonqualified Deferred Compensation table include deferrals and the company match under the Salary Deferral Program. The amounts reported as “Executive Contributions in Last FY” are salary deferrals and are also included as “Salary” in the Summary Compensation Table. Under EFH Corp.’s Salary Deferral Program each employee of EFH Corp. and its participating subsidiaries who is in a designated job level and whose annual salary is equal to or greater than an amount established under the Salary Deferral Program ($110,840 for the program year beginning January 1, 2009) may elect to defer up to 50% of annual base salary, and/or up to 100% of any bonus or incentive award, for a maturity period of seven years, for a maturity period ending with the retirement of such employee, or for a combination thereof. EFH Corp. makes a matching award, which vests at the end of the applicable maturity period (subject to acceleration or forfeiture under certain circumstances), equal to 100% of up to the first 8% of salary deferred under the Salary Deferral Program. Deferrals are credited with earnings or losses based on the performance of investment alternatives under the Salary Deferral Program selected by each participant. At the end of the applicable maturity period, the trustee for the Salary Deferral Program distributes the deferred compensation, any vested matching awards and the applicable earnings in cash as a lump sum or in annual installments at the participant’s election made at the time of deferral. EFH Corp. is financing the retirement option portion of the Salary Deferral Program through the purchase of corporate-owned life insurance on the lives of participants. The proceeds from such insurance are expected to allow EFH Corp. to fully recover the cost of the retirement option. Beginning in 2010, certain executive officers, including the Named Executive Officers, will not be eligible to participate in the Salary Deferral Program. |
| (2) | The amount included in “Registrant Contributions in Last FY” is attributable to EFH Corp.’s matching award under the Salary Deferral Program. |
| (3) | The “Aggregate Withdrawals/Distributions($)” column excludes amounts transferred from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan as of December 31, 2009 for Messrs. Young ($37,500), Keglevic ($48,511), Walters ($71,283) and Burke ($25,000). In accordance with the terms of the Salary Deferral Plan, Mr. Chand forfeited $39,606 of company matching and received a distribution of the remaining balance of his account upon termination of his employment. |
| (4) | A portion of the amounts reported as “Aggregate Balance at Last FYE” are also included in the Summary Compensation Table as follows: for Mr. Young, $80,000 and $66,667 of executive contributions are included as “Salary” for 2009 and 2008, respectively, and $80,000 and $66,667 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively; for Mr. Keglevic, $48,000 and $20,000 of executive contributions are included as “Salary” for 2009 and 2008, respectively, and $48,000 and $20,000 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively; for Mr. Walters, $46,000 and $30,667 of executive contributions are included as “Salary” for 2009 and 2008, respectively, and $46,000 and $30,667 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively; for Mr. Burke, $48,000 and $27,417 of executive contributions are included as “Salary” for 2008 and 2007, respectively, and $48,000 and $27,417 of company matching contributions are included as “All Other Compensation” for 2009 and 2008, respectively. The amounts reported as “Aggregate Balance at Last FYE” reflect decreases resulting from the amounts transferred from the Supplemental Retirement Plan and/or Salary Deferral Program to the cash balance component of the Retirement Plan as of December 31, 2009 for Messrs. Young ($37,500), Keglevic ($48,511), Walters ($71,283) and Burke ($25,000) |
Potential Payments upon Termination or Change in Control
The tables and narrative below provide information for payments to each of the Named Executive Officers (or, as applicable, enhancements to payments or benefits) in the event of his termination, including if such termination is voluntary, for cause, as a result of death, as a result of disability, without cause or for good reason or without cause or for good reason in connection with a change in control.
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The information in the tables below is presented in accordance with SEC rules, assuming termination of employment as of December 31, 2009.
Employment Arrangements with Contingent Payments
As of December 31, 2009, each of Messrs. Young, Keglevic, Campbell, Walters and Burke had employment agreements with change in control and severance provisions as described in the following tables. In addition, in October 2009, the O&C Committee approved several changes to the compensation arrangements for all of the Named Executive Officers other than Messrs. Young and Chand, which changes were effective as of December 31, 2009 but not yet documented in such Named Executive Officers’ employment agreements. Certain of these changes affected the potential payments of Messrs. Keglevic, Campbell, Walters and Burke and are reflected in the following tables. In February, 2010, Mr. Young’s employment agreement was amended and restated effective retroactively on January 1, 2010. Because the changes to Mr. Young’s employment agreement were not effective as of December 31, 2009, they are not reflected in the following table for Mr. Young, but are described elsewhere in this Form 10-K. Mr. Chand had an employment agreement, and the change in control and severance terms included in the employment agreement governed until his employment with EFH Corp. terminated in October 2009.
With respect to each Named Executive Officer’s employment agreement, a change in control is generally defined as (i) a transaction that results in a sale of substantially all of our assets to another person and such person having more seats on our Board than the Sponsor Group, (ii) a transaction that results in a person not in the Sponsor Group owning more than 50% of our common stock and such person having more seats on our Board than the Sponsor Group or (iii) a transaction that results in the Sponsor Group owning less than 20% of our common stock and the Sponsor Group not being able to appoint a majority of the directors to our Board.
Each Named Executive Officer’s employment agreement includes customary non-compete and non-solicitation provisions that generally restrict the Named Executive Officer’s ability to compete with us or solicit our customers or employees for his own personal benefit during the term of the employment agreement and 24 months (with respect to Mr. Young) or 18 months (with respect to Messrs. Keglevic, Campbell, Walters and Burke) after the employment agreement expires or is terminated.
In addition, in October 2009, the O&C Committee approved the adoption of a new LTI to be included by amendment in the employment agreement of Messrs. Keglevic, Campbell, Walters and Burke. Under the terms of the LTI, in the event of the death or disability of any such Named Executive Officer, his termination without cause or resignation for good reason (or in the event we elect not to extend his employment term), or his termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp., in each case prior to September 30, 2012, such named Executive Officer shall be entitled to receive the LTI, or a pro rata portion thereof, calculated as (i) 75% of the aggregate EAIP award actually earned by the Named Executive Officer for any applicable fiscal year completed prior to the date of the Named Executive Officer’s termination, plus (ii) for a termination occurring in fiscal year 2009, 2010, or 2011, 75% of the Named Executive Officer’s prorated annual performance-based cash bonus for the year of termination. In February 2010, Mr. Young’s employment agreement was amended to add a similar new LTI that is calculated based on 100% of the aggregate EAIP award actually earned by Mr. Young for fiscal years 2009, 2010 and 2011.
As of December 31, 2009, each of Messrs. Young, Keglevic, Campbell, Walters and Burke had stock option agreements. Under the stock option agreement for each Named Executive Officer, in the event of such Named Executive Officer’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) following a change in control of EFH Corp., such Named Executive Officer’s Original Time Vested Options would become immediately exercisable as to 100% of the shares of EFH Corp. common stock subject to such options immediately prior to the change in control. As of December 31, 2009, the fair market value of the shares of EFH Corp. common stock underlying each Named Executive Officer’s Original Time Vested Options was less than the exercise price of such options.
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1. Mr. Young
Potential Payments to Mr. Young upon Termination as of December 31, 2009 (per employment agreement, restricted stock agreement and stock option agreement, each in effect as of December 31, 2009)
Benefit | Voluntary | For Cause | Death | Disability | Without Cause Or For Good Reason | Without Cause Or For Good Reason In Connection With Change in Control | |||||||||||||
Cash Severance | N/A | N/A | N/A | N/A | $ | 5,000,000 | $ | 5,000,000 | |||||||||||
EAIP | N/A | N/A | $ | 1,000,000 | $1,000,000 | N/A | $ | 1,000,000 | |||||||||||
Payment of Common Stock in respect of Restricted Stock Units | N/A | $ | 1,950,000 | $1,950,000 | $ | 1,950,000 | $ | 1,950,000 | $ | 1,950,000 | |||||||||
Acceleration of Stock Option Awards | N/A | N/A | N/A | N/A | N/A | $ | 0 | ||||||||||||
Deferred Compensation | |||||||||||||||||||
- Salary Deferral Program | N/A | N/A | $159,608 | $ | 159,608 | N/A | $ | 159,608 | |||||||||||
Health & Welfare | |||||||||||||||||||
- Medical/COBRA | N/A | N/A | N/A | N/A | $ | 33,273 | $ | 33,273 | |||||||||||
- Dental/COBRA | N/A | N/A | N/A | N/A | $ | 2,790 | $ | 2,790 | |||||||||||
Totals | N/A | $ | 1,950,000 | $3,109,608 | $ | 3,109,608 | $ | 6,986,063 | $ | 8,145,671 | |||||||||
Mr. Young has entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
| 1. | In the event of Mr. Young’s death or disability: |
| a. | a prorated annual incentive bonus for the year of termination, and |
| b. | payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled. |
2. In the event of Mr. Young’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):
| a. | a lump sum payment equal to two and one-half times the sum of (i) his annualized base salary and (ii) a prorated annual incentive bonus for the year of termination; |
| b. | payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled, and |
| c. | certain continuing health care and company benefits. |
3. In the event of Mr. Young’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:
| a. | a lump sum payment equal to two and one-half times the sum of (i) his annualized base salary and (ii) his annual bonus target; |
| b. | a prorated annual incentive bonus for the year of termination; |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. Young may be entitled; |
| d. | certain continuing health care and company benefits, and |
| e. | a tax gross-up payment to offset any excise tax which may result from the change in control payments. |
In addition, Mr. Young has entered into a restricted stock agreement. Under Mr. Young’s restricted stock agreement, Mr. Young was granted 600,000 restricted stock units, payable in January 2010, with one share of common stock of EFH Corp. for each such unit, all of which were fully vested and nonforfeitable upon grant; provided, however, in the event of Mr. Young’s voluntary termination prior to January 2010, Mr. Young would have had to forfeit all of his restricted stock units.
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2. Mr. Keglevic
Potential Payments to Mr. Keglevic upon Termination as of December 31, 2009 (per employment agreement, deferred share agreement and stock option agreement, each in effect as of December 31, 2009, and revisions to such employment agreement that were adopted by the O&C Committee in October 2009 and effective as of December 31, 2009)
Benefit | Voluntary | For Cause | Death | Disability | Without Cause Or For Good Reason | Without Cause Or For Good Reason In Connection With Change in Control | ||||||||||
Cash Severance | N/A | N/A | N/A | N/A | $ | 2,100,000 | $ | 2,100,000 | ||||||||
EAIP | N/A | N/A | $ | 450,000 | $ | 450,000 | N/A | N/A | ||||||||
Put Right in respect of Deferred Shares | N/A | N/A | $ | 3,200,000 | $ | 3,200,000 | $ | 3,200,000 | $ | 3,200,000 | ||||||
Acceleration of Stock Option Awards | N/A | N/A | N/A | N/A | N/A | $ | 0 | |||||||||
LTI Cash Retention Award | N/A | N/A | $ | 498,150 | $ | 498,150 | $ | 498,150 | $ | 498,150 | ||||||
Deferred Compensation | ||||||||||||||||
- Salary Deferral Program | N/A | N/A | $ | 68,107 | $ | 68,107 | N/A | $ | 68,107 | |||||||
Health & Welfare | ||||||||||||||||
- Dental/COBRA | N/A | N/A | N/A | N/A | $ | 2,790 | $ | 2,790 | ||||||||
Totals | N/A | N/A | $ | 4,216,257 | $ | 4,216,257 | $ | 5,800,940 | $ | 5,869,047 | ||||||
Mr. Keglevic entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
1. In the event of Mr. Keglevic’s death or disability:
| a. | a prorated annual incentive bonus for the year of termination, and |
| b. | payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled. |
2. In the event of Mr. Keglevic’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):
| a. | for a termination occurring on or prior to the second anniversary of the effective date of the agreement, a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target, and for a termination occurring after the second anniversary of the effective date of the agreement, a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination and (iii) the matching contributions which would have been made on his behalf to EFH Corp.’s Salary Deferral Program had Mr. Keglevic continued his participation in the plan for an additional twelve months; |
| b. | payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled, and |
| c. | certain continuing health care and company benefits. |
3. In the event of Mr. Keglevic’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:
| a. | a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target; |
| b. | payment of employee benefits, including stock compensation, if any, to which Mr. Keglevic may be entitled; |
| c. | certain continuing health care and company benefits, and |
| d. | a tax gross-up payment to offset any excise tax which may result from the change in control payments. |
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In addition, Mr. Keglevic has entered into a deferred share agreement. Under Mr. Keglevic’s deferred share agreement, EFH Corp. agreed to deliver to Mr. Keglevic 112,500 shares of EFH Corp. common stock on July 1, 2011 and 112,500 shares of EFH Corp. common stock on July 1, 2013; provided, however, that any shares not yet vested shall become 100% vested and become nonforfeitable in the event of Mr. Keglevic’s death or disability or as a result of his termination without cause or for good reason or without cause or for good reason in connection with a change in control. Further, in the event of Mr. Keglevic’s termination prior to July 1, 2013 as a result of death, as a result of disability, without cause or for good reason or without cause or for good reason in connection with a change in control, Mr. Keglevic shall have the right (but not the obligation) to sell to EFH Corp. all (but not less than all) of the shares of EFH Corp. common stock delivered pursuant to the deferred share agreement for a purchase price of $3,200,000.
3. Mr. Campbell
Potential Payments to Mr. Campbell upon Termination as of December 31, 2009 (per employment agreement, deferred share agreement and stock option agreement, each in effect as of December 31, 2009, and revisions to such employment agreement that were adopted by the O&C Committee in October 2009 and effective as of December 31, 2009)
Benefit | Voluntary | For Cause | Death | Disability | Without Cause Or For Good Reason | Without Cause Or For Good Reason In Connection With Change in Control | ||||||||||||
Cash Severance | N/A | N/A | N/A | N/A | $ | 2,100,000 | $ | 2,100,000 | ||||||||||
EAIP | N/A | N/A | $ | 450,000 | $ | 450,000 | N/A | N/A | ||||||||||
Payment of EFH Corp. Common Stock in respect of Vested Deferred Shares | $ | 1,625,000 | $ | 1,625,000 | $ | 1,625,000 | $ | 1,625,000 | $ | 1,625,000 | $ | 1,625,000 | ||||||
Acceleration of Stock Option Awards | N/A | N/A | N/A | N/A | N/A | $ | 0 | |||||||||||
LTI Cash Retention Award | N/A | N/A | $ | 481,950 | $ | 481,950 | $ | 481,950 | $ | 481,950 | ||||||||
Retirement Benefits | ||||||||||||||||||
- Supplemental Retirement Plan | $ | 43,511 | $ | 43,511 | $ | 45,205 | $ | 271,531 | $ | 43,511 | $ | 43,511 | ||||||
Deferred Compensation | ||||||||||||||||||
- Salary Deferral Program (1) | $ | 77,146 | $ | 77,146 | $ | 77,146 | $ | 77,146 | $ | 77,146 | $ | 77,146 | ||||||
Health & Welfare | ||||||||||||||||||
- Medical/COBRA | N/A | N/A | N/A | N/A | $ | 26,719 | $ | 26,719 | ||||||||||
- Dental/COBRA | N/A | N/A | N/A | N/A | $ | 2,232 | $ | 2,232 | ||||||||||
Totals | $ | 1,745,657 | $ | 1,745,657 | $ | 2,679,301 | $ | 2,905,627 | $ | 4,356,558 | $ | 4,356,558 | ||||||
| (1) | Mr. Campbell is fully vested in the company matching portion of the Salary Deferral Plan. |
Mr. Campbell entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
1. In the event of Mr. Campbell’s death or disability:
| a. | a prorated annual incentive bonus for the year of termination, and |
| b. | payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled. |
2. In the event of Mr. Campbell’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):
| a. | for a termination occurring on or prior to the second anniversary of the effective date of the agreement, a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target, and for a termination occurring after the second anniversary of the effective date of the agreement, a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination and (iii) the matching contributions which would have been made on his behalf to EFH Corp.’s |
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Salary Deferral Program had Mr. Campbell continued his participation in the plan for an additional twelve months; |
| b. | payment of employee benefits, including stock compensations, if any, to which Mr. Campbell may be entitled, and |
| c. | certain continuing health care and company benefits. |
3. In the event of Mr. Campbell’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:
| a. | a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target; |
| b. | payment of employee benefits, including stock compensation, if any, to which Mr. Campbell may be entitled; |
| c. | certain continuing health care and company benefits, and |
| d. | a tax gross-up payment to offset any excise tax which may result from the change in control payments. |
In addition, Mr. Campbell has entered into a deferred share agreement. Under Mr. Campbell’s deferred share agreement, EFH Corp. agreed to deliver to Mr. Campbell 500,000 shares of EFH Corp. common stock in the event of Mr. Campbell’s termination for any reason.
4. Mr. Walters
Potential Payments to Mr. Walters upon Termination as of December 31, 2009 (per employment agreement and stock option agreement, each in effect as of December 31, 2009, and revisions to such employment agreement that were adopted by the O&C Committee in October 2009 and effective as of December 31, 2009)
Benefit | Voluntary | For Cause | Death | Disability | Without Cause Or For Good Reason | Without Cause Or For Good Reason In Connection With Change in Control | ||||||||||
Cash Severance | N/A | N/A | N/A | N/A | $ | 2,012,500 | $ | 2,012,500 | ||||||||
EAIP | N/A | N/A | $ | 431,250 | $ | 431,250 | N/A | N/A | ||||||||
Acceleration of Stock Option Awards | N/A | N/A | N/A | N/A | N/A | $ | 0 | |||||||||
LTI Cash Retention Award | N/A | N/A | $ | 457,500 | $ | 457,500 | $ | 457,500 | $ | 457,500 | ||||||
Lump Sum Payment | N/A | N/A | $ | 2,000,000 | $ | 2,000,000 | $ | 2,000,000 | $ | 2,000,000 | ||||||
Deferred Compensation | ||||||||||||||||
- Salary Deferral Program | N/A | N/A | $ | 87,343 | $ | 87,343 | N/A | $ | 87,343 | |||||||
Health & Welfare | ||||||||||||||||
- Medical/COBRA | N/A | N/A | N/A | N/A | $ | 26,618 | $ | 26,618 | ||||||||
- Dental/COBRA | N/A | N/A | N/A | N/A | $ | 2,232 | $ | 2,232 | ||||||||
Totals | N/A | N/A | $ | 2,976,093 | $ | 2,976,093 | $ | 4,498,850 | $ | 4,586,193 | ||||||
Mr. Walters entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
1. In the event of Mr. Walters’ death or disability:
| a. | a prorated annual incentive bonus for the year of termination; |
| b. | a lump sum payment equal to $2,000,000, and |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. Walters may be entitled. |
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2. In the event of Mr. Walters’ termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):
| a. | for a termination occurring on or prior to the second anniversary of the effective date of the agreement, a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target, and for a termination occurring after the second anniversary of the effective date of the agreement, a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination and (iii) the matching contributions which would have been made on his behalf to EFH Corp.’s Salary Deferral Program had Mr. Walters continued his participation in the plan for an additional twelve months; |
| b. | a lump sum payment equal to $2,000,000; |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. Walters may be entitled, and |
| d. | certain continuing health care and company benefits. |
3. In the event of Mr. Walters’ termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:
| a. | a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target; |
| b. | a lump sum payment equal to $2,000,000; |
| c. | payment of employee benefits, including stock compensation, if any, to which Mr. Walters may be entitled; |
| d. | certain continuing health care and company benefits, and |
| e. | a tax gross-up payment to offset any excise tax which may result from the change in control payments. |
5. Mr. Burke
Potential Payments to Mr. Burke upon Termination as of December 31, 2009 (per employment agreement and stock option agreement, each in effect as of December 31, 2009, and revisions to such employment agreement that were adopted by the O&C Committee in October 2009 and effective as of December 31, 2009)
Benefit | Voluntary | For Cause | Death | Disability | Without Cause Or For Good Reason | Without Cause Or For Good Reason In Connection With Change in Control | ||||||||||||
Cash Severance | N/A | N/A | N/A | N/A | $ | 1,200,000 | $ | 2,100,000 | ||||||||||
EAIP | N/A | N/A | $ | 450,000 | $ | 450,000 | $ | 450,000 | N/A | |||||||||
Acceleration of Stock Option Awards | N/A | N/A | N/A | N/A | N/A | $ | 0 | |||||||||||
LTI Cash Retention Award | N/A | N/A | $ | 642,600 | $ | 642,600 | $ | 642,600 | $ | 642,600 | ||||||||
Retirement Benefits | ||||||||||||||||||
- Supplemental Retirement Plan | $ | 35,747 | $ | 35,747 | $ | 38,099 | $ | 255,572 | $ | 35,747 | $ | 35,747 | ||||||
Deferred Compensation | ||||||||||||||||||
- Salary Deferral Program | $ | 66,775 | $ | 66,775 | $ | 128,976 | $ | 128,976 | $ | 66,775 | $ | 128,976 | ||||||
Health & Welfare | ||||||||||||||||||
- Medical/COBRA | N/A | N/A | N/A | N/A | $ | 26,618 | $ | 26,618 | ||||||||||
- Dental/COBRA | N/A | N/A | N/A | N/A | $ | 2,232 | $ | 2,232 | ||||||||||
Totals | $ | 102,522 | $ | 102,522 | $ | 1,259,675 | $ | 1,477,148 | $ | 2,423,972 | $ | 2,936,173 | ||||||
Mr. Burke entered into an employment agreement that provides for certain payments and benefits upon the expiration or termination of the agreement under the following circumstances:
1. In the event of Mr. Burke’s death or disability:
| a. | a prorated annual incentive bonus for the year of termination, and |
| b. | payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled. |
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2. In the event of Mr. Burke’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term):
| a. | a lump sum payment equal to (i) two times his annualized base salary, (ii) a prorated annual incentive bonus for the year of termination and (iii) the matching contributions which would have been made on his behalf to EFH Corp.’s Salary Deferral Program had Mr. Burke continued his participation in the plan for an additional twelve months; |
| b. | payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled, and |
| c. | certain continuing health care and company benefits. |
3. In the event of Mr. Burke’s termination without cause or resignation for good reason (or in the event we elect not to extend his employment term) within 24 months following a change in control of EFH Corp.:
| a. | a lump sum payment equal to two times the sum of (i) his annualized base salary and (ii) his annual bonus target; |
| b. | payment of employee benefits, including stock compensation, if any, to which Mr. Burke may be entitled; |
| c. | certain continuing health care and company benefits and |
| d. | a tax gross-up payment to offset any excise tax which may result from the change in control payments. |
6. Mr. Chand
Mr. Chand’s employment with EFH Corp. terminated in October 2009. Under the terms of his Severance Agreement, EFH Corp. provided Mr. Chand a severance payment which consisted of a lump sum cash payment of (i) $1,485,000, representing the cash severance that was due under his employment agreement and (ii) $600,000 related to his deferred share agreement.
Excise Tax Gross-Ups
Pursuant to their employment agreements, if any of our Named Executive Officers would be subject to the imposition of the excise tax imposed by Section 4999 of the Code, related to the executive’s employment, but the imposition of such tax could be avoided by approval of our shareholders as described in Section 280G(b)(5)(B) of the Code, then such executive may cause EFH Corp. to seek such approval, in which case EFH Corp. will use its reasonable best efforts to cause such approval to be obtained and such executive will cooperate and execute such waivers as may be necessary so that such approval avoids imposition of any excise tax under Section 4999. If such executive fails to cause EFH Corp. to seek such approval or fails to cooperate and execute the waivers necessary in the approval process, such executive shall not be entitled to any gross-up payment for any resulting tax under Section 4999.
Compensation Committee Interlocks and Insider Participation
There are no relationships among our executive officers, members of the O&C Committee or entities whose executives served on the O&C Committee that required disclosure under applicable SEC rules and regulations. For a description of related person transactions involving members of the O&C Committee, see Item 13, entitled “Related Person Transactions.”
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Director Compensation
The table below sets forth information regarding the aggregate compensation paid to the members of the Board during the year ended December 31, 2009. Directors who are officers of EFH Corp. or members of the Sponsor Group (or their respective affiliates) do not receive any fees for service as a director.EFH Corp. reimburses directors for certain reasonable expenses incurred in connection with their services as directors.
Name | Fees Earned or Paid in Cash ($) | Stock Awards ($) | All Other Compensation ($) | Total ($) | ||||
Arcilia C. Acosta (1) | 150,000 | 100,000 | — | 250,000 | ||||
David Bonderman | — | — | — | — | ||||
Donald L. Evans (2) | 2,000,000 | 425,000 | 0 | 2,425,000 | ||||
Thomas D. Ferguson | — | — | — | — | ||||
Frederick M. Goltz | — | — | — | — | ||||
James R. Huffines (1)(3) | 150,000 | 100,000 | 900,000 | 1,150,000 | ||||
Scott Lebovitz | — | — | — | — | ||||
Jeffrey Liaw | — | — | — | — | ||||
Marc S. Lipschultz | — | — | — | — | ||||
Michael MacDougall | — | — | — | — | ||||
Lyndon L. Olson, Jr. (1)(3) | 150,000 | 100,000 | 900,000 | 1,150,000 | ||||
Kenneth Pontarelli | — | — | — | — | ||||
William K. Reilly (1) | 150,000 | 100,000 | 0 | 250,000 | ||||
Jonathan D. Smidt | — | — | — | — | ||||
John F. Young | — | — | — | — | ||||
Kneeland Youngblood (1) | 150,000 | 100,000 | 0 | 250,000 |
| (1) | Ms. Acosta and Messrs. Huffines, Olson, Reilly and Youngblood receive $150,000 annually and an annual equity award (paid in shares of EFH Corp. common stock) valued at $100,000 (the grant date fair value) for their service as a director. |
| (2) | In May 2008, EFH Corp. entered into a consulting agreement with Mr. Evans, pursuant to which he received the following compensation: |
| 1. | An annual fee of $2,000,000; and |
| 2. | 200,000 shares of restricted stock, half of which vested during 2009, 50,000 shares at $5.00 per share and 50,000 shares at $3.50 per share. The value of the shares that vested during 2009 is reported in the table above under the heading “Stock Awards”. |
Under the consulting agreement, Mr. Evans also received options to purchase 600,000 shares of EFH Corp.’s common stock at an exercise price of $5.00 per share. As a result, there should have been an “Option Awards” column in last year’s Director Compensation table and it should have included $551,250 as the grant date fair value for the options granted to Mr. Evans in May 2008 based upon rules for valuing stock option awards as they existed last year. The consulting agreement had a term running through October 2009. In February 2010, EFH Corp. entered into a new consulting agreement with Mr. Evans effective retroactively to October 10, 2009, pursuant to which Mr. Evans is entitled to receive an annual fee of $2,000,000. The term of the new consulting agreement expires in October 2012.
| (3) | In December 2007, EFH Corp. entered into consulting agreements with Messrs. Huffines and Olson. As compensation for their consulting services, they received annual fees of $225,000, in addition to their standard director compensation described above. The amounts earned pursuant to these consulting agreements in 2009 are reflected above in the “All Other Compensation” column. In November 2009, the consulting agreements with Messrs. Huffines and Olson were terminated. In January 2010, Messrs. Huffines and Olson were each paid a $675,000 bonus for their exemplary efforts and past performance while serving as consultants. |
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| 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, 2009. (See Note 22 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 | 62,289,801 | $ | 4.61 | 9,710,199 | |||
| 62,289,801 | $ | 4.61 | 9,710,199 | ||||
| Note: | Includes 49.8 million stock options with a weighted average exercise price of $4.63. | |
| Includes 4.0 million vested and unvested restricted shares, deferred shares and stock granted to directors as part of their compensation plan. | ||
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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 current and former executive officers of EFH Corp. and the holders of more than 5% of EFH Corp.’s common stock as of February 1, 2010.
Name | Number of Shares Beneficially Owned | Percent of Class | |||
Texas Energy Future Holdings Limited Partnership (1) | 1,657,600,000 | 98.40 | % | ||
Arcilia C. Acosta (2) | 70,000 | * | |||
David Bonderman (3) | 1,657,600,000 | 98.40 | % | ||
Donald L. Evans (4) | 1,000,000 | * | |||
Thomas D. Ferguson (5) | 1,657,600,000 | 98.40 | % | ||
Frederick M. Goltz (6) | 1,657,600,000 | 98.40 | % | ||
James R. Huffines | 360,000 | * | |||
Scott Lebovitz (5) | 1,657,600,000 | 98.40 | % | ||
Jeffrey Liaw (3) | 1,657,600,000 | 98.40 | % | ||
Marc S. Lipschultz (6) | 1,657,600,000 | 98.40 | % | ||
Michael MacDougall (3) | 1,657,600,000 | 98.40 | % | ||
Lyndon L. Olson, Jr. | 220,000 | * | |||
Kenneth Pontarelli (5) | 1,657,600,000 | 98.40 | % | ||
William K. Reilly | 200,000 | * | |||
Jonathan D. Smidt (6) | 1,657,600,000 | 98.40 | % | ||
John F. Young (7) | 3,450,000 | * | |||
Kneeland Youngblood | 140,000 | * | |||
James A. Burke (8) | 1,185,000 | * | |||
David A. Campbell (9) | 1,700,000 | * | |||
M. Rizwan Chand (10) | 350,000 | * | |||
Paul M. Keglevic (11) | 975,000 | * | |||
Robert C. Walters (12) | 600,000 | * | |||
M. A. McFarland (13) | 500,000 | * | |||
All directors and current executive officers as a group (28 persons) | 1,671,979,000 | 99.26 | % |
| * | 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) | Shares held in a family limited partnership, ACA Family LP. |
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| (3) | Includes the 1,657,600,000 shares owned by Texas Holdings, over which TPG Partners V, L.P., TPG Partners IV, L.P., TPG FOF V-A, L.P. and TPG FOF V-B, L.P. (TPG Entities) may be deemed, as a result of their ownership of 27.01% of Texas Capital’s outstanding units and certain provisions of Texas Capital’s Amended and Restated Limited Liability Company Agreement (TC LLC Agreement), to have shared voting or dispositive power. The ultimate general partners of the TPG Entities are TPG Advisors IV, Inc. and TPG Advisors V, Inc. David Bonderman and James Coulter are the sole shareholders and directors of TPG Advisors IV Inc. and TPG Advisors V Inc., and therefore, Messrs. Bonderman and Coulter, TPG Advisors IV Inc. and TPG Advisors V Inc. may each be deemed to beneficially own the shares held by the TPG Entities. Messrs. Bonderman, Liaw and MacDougall are managers of Texas Capital. By virtue of their position in relation to Texas Capital and the TPG Entities, Messrs. Bonderman, Liaw and MacDougall may be deemed to have beneficial ownership with respect to the shares of EFH Corp. common stock owned by Texas Holdings. Each of Messrs. Liaw and MacDougall disclaims beneficial ownership of such shares except to the extent of their pecuniary interest in those shares. The address of each entity and individual listed in this footnote is 301 Commerce Street, Suite 3300, Fort Worth, Texas 76102. |
| (4) | Includes 600,000 shares issuable upon exercise of vested options. |
| (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 2,250,000 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 735,000 shares issuable upon exercise of vested options. |
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| (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 1,200,000 shares issuable upon exercise of vested options. |
| (10) | Includes 350,000 shares issuable upon exercise of vested options. |
| (11) | Includes 225,000 deferred shares which, in accordance with the terms of the Deferred Share Agreement, will be settled in shares of EFH Corp. common stock upon the earlier of termination of employment or a change in control of EFH Corp. and 750,000 shares issuable upon exercise of vested options. |
| (12) | Includes 600,000 shares issuable upon exercise of vested options. |
| (13) | Includes 100,000 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 400,000 shares issuable upon exercise of vested options. |
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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 if the transaction is on terms comparable to those that could be obtained in arm’s length dealings with an unrelated third party; |
| 2. | the transaction is approved by the disinterested members of the Board or the Executive Committee; or |
| 3. | the transaction involves compensation approved by the Organization and Compensation Committee of the Board. |
For purposes of this policy, the term “related person” includes EFH Corp.’s directors, executive officers, 5% shareholders and their immediate family members. “Immediate family members” means any child, stepchild, parent, stepparent, spouse, sibling, mother-in-law, father-in-law, son-in-law, daughter-in-law, brother-in-law or sister-in-law or any person (other than a tenant or employee) sharing the household of a director, executive officer or 5% shareholder.
A “related person transaction” is a transaction between EFH Corp. or its subsidiaries and a related person, other than the types of transactions described below, which are deemed to be pre-approved by the Audit Committee of the Board:
| 1. | any compensation paid to a director if the compensation is required to be reported under Item 402 of Regulation S-K of the Securities Act; |
| 2. | any transaction with another company at which a related person’s only relationship is as an employee (other than an executive officer), director or beneficial owner of less than 10% of that company’s ownership interests; |
| 3. | any charitable contribution, grant or endowment by EFH Corp. to a charitable organization, foundation or university at which a related person’s only relationship is as an employee (other than an executive officer) or director; |
| 4. | transactions where the related person’s interest arises solely from the ownership of EFH Corp.’s equity securities and all holders of that class of equity securities received the same benefit on a pro rata basis; |
| 5. | transactions involving a related party where the rates or charges involved are determined by competitive bids; |
| 6. | any transaction with a related party involving the rendering of services as a common or contract carrier, or public utility, as rates or charges fixed in conformity with law or governmental authority; |
| 7. | any transaction with a related party involving services as a bank depositary of funds, transfer agent, registrar, trustee under a trust indenture, or similar service; |
| 8. | transactions available to all employees or customers generally (unless required to be disclosed under Item 404 of Regulation S-K of the Securities Act, if applicable); |
| 9. | transactions involving less than $100,000 when aggregated with all similar transactions; |
| 10. | transactions between EFH Corp. and its subsidiaries or between subsidiaries of EFH Corp.; |
| 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. shall make all reasonable efforts to cancel or otherwise terminate such transactions.
The related person transactions described below under “Related Person Transactions – Business Affiliations,” were ratified by the Audit Committee of the Board pursuant to the policy described above. All other related person transactions were approved prior to the Board’s adoption of this policy, but were approved by either the Board or its Executive Committee. Transactions described 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, Greene, Campbell, Walters, Burke, Keglevic, McFarland, Enze, Kaplan and Landy, each of whom are executive officers of EFH Corp., became parties to this agreement.
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Management Services Agreement
In October 2007, in connection with the Merger, the Sponsor Group and Lehman Brothers Inc. entered into a management agreement with EFH Corp. (Management Agreement), pursuant to which affiliates of the Sponsor Group provide management, consulting, financial and other advisory services to EFH Corp. Pursuant to the Management Agreement, affiliates of the Sponsor Group are entitled to receive an aggregate annual management fee of $35 million, which amount increases 2% annually, and reimbursement of out-of-pocket expenses incurred in connection with the provision of services pursuant to the Management Agreement. The Management Agreement will continue in effect from year to year, unless terminated upon a change of control of EFH Corp. or in connection with an initial public offering of EFH Corp. or if the parties thereto mutually agree to terminate the Management Agreement. Pursuant to the Management Agreement, affiliates of the Sponsor Group and Lehman Brothers Inc. were paid transaction fees of $300 million for certain services provided in connection with the Merger and related transactions. In addition, the Management Agreement provides that the Sponsor Group will be entitled to receive a fee equal to a percentage of the gross transaction value in connection with certain subsequent financing, acquisition, disposition, merger combination and change of control transactions, as well as a termination fee based on the net present value of future payment obligations under the Management Agreement in the event of an initial public offering or under certain other circumstances. Under terms of the Management Agreement, EFH Corp. paid $36 million, inclusive of expenses, to the Sponsor Group during 2009.
Indemnification Agreement
Concurrently with entering into the Management Agreement, the Sponsor Group, Texas Holdings and EFH Corp. entered into an indemnification agreement (Indemnification Agreement), pursuant to which EFH Corp. and Texas Holdings agree to indemnify the Sponsor Group and their affiliates against any claims relating to (i) certain securities and financing transactions relating to the Merger, (ii) the performance of transaction services pursuant to the Management Agreement, (iii) actions or failures to act by EFH Corp., Texas Holdings, Texas Capital or their subsidiaries or affiliates (collectively, Company Group), (iv) service as an officer or director of, or at the request of, any member of the Company Group, and (v) any breach or alleged breach of fiduciary duty as a director or officer of any member of the Company Group.
Sale Participation Agreement
Ms. Acosta and Messrs. Evans, Huffines, Olson, Reilly and Youngblood, each of whom are members of our Board, and each of our executive officers have entered into sale participation agreements with EFH Corp. Pursuant to the terms of these agreements, among other things, shares of EFH Corp.’s common stock held by these individuals are subject to tag-along and drag-along rights in the event of a sale by the Sponsor Group of shares of EFH Corp.’s common stock held by the Sponsor Group.
Certain Charter Provisions
EFH Corp.’s restated certificate of formation contains provisions limiting directors’ obligations in respect of corporate opportunities.
Management Stockholders’ Agreement
Subject to a management stockholders’ agreement, certain members of management, including EFH Corp.’s directors, executive officers, along with other members of management, elected to invest in EFH Corp. by contributing cash or common stock, or a combination of both, to EFH Corp. prior to or following the Merger and receiving common stock in EFH Corp. in exchange therefore. The net aggregate amount of this investment as of December 31, 2009 is approximately $42.6 million. The management stockholders’ agreement creates certain rights and restrictions on these shares of common stock, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances.
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Director Stockholders’ Agreement
Certain members of our Board have entered into a stockholders’ agreement with EFH Corp. These stockholders’ agreements create certain rights and restrictions on the equity, including transfer restrictions and tag-along, drag-along, put, call and registration rights in certain circumstances.
Business Affiliations
Mr. Olson, a member of our board, has an ownership interest in two companies with which Oncor does business. These companies are Texas Meter and Device Company (TMD) and Metrum Technologies LLC (Metrum). Mr. Olson and his brother collectively directly own approximately 24% of TMD and indirectly own approximately 19% of Metrum. Both entities are majority owned by their chief executive officer. In 2009, Oncor paid TMD approximately $1.2 million and paid Metrum approximately $0.2 million. TMD tests Oncor’s high voltage personal protective equipment. Metrum provides Oncor with cellular-based wireless communications equipment for its meters. Oncor is Metrum’s largest customer. The business relationships with both TMD and Metrum commenced several years prior to Mr. Olson joining the Board.
Transactions with Sponsor Affiliates
TCEH has entered into the TCEH Senior Secured Facilities, and Oncor has entered into a revolving credit facility, each with syndicates of financial institutions and other lenders. These syndicates included affiliates of GS Capital Partners. These transactions were approved by the Board of Directors.
Affiliates of the Sponsor Group participated in the debt exchange offers completed in November 2009 by EFH Corp., Intermediate Holding and EFIH Finance to exchange new senior secured notes for certain EFH Corp. and TCEH notes (see Note 12 to Financial Statements for additional information). Goldman, Sachs & Co. and KKR Capital Markets LLC were paid customary fees in the amounts of $750,000 and $260,000, respectively, as compensation for their services as dealer managers in the debt exchange offers and TPG Capital, L.P. received a fee in the amount of $260,000 as compensation for the advisory services it rendered in connection with the debt exchange offers.
Also, Goldman, Sachs & Co. acted as an initial purchaser in EFH Corp.’s issuance of $500 million principal amount of senior secured notes completed in January 2010. (See Note 12 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 Sachs & Co. are party to certain commodity and interest rate hedging transactions with EFH Corp. in the normal course of business.
From time to time affiliates of the Sponsor Group may acquire debt or debt securities issued by EFH Corp. or its subsidiaries in open market transactions or through loan syndications.
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 with the SEC or traded on any national securities exchange, based upon the listing standards for issuers of equity securities on the New York Stock Exchange, the national securities exchange upon which EFH Corp.’s common stock was traded prior to the Merger, only Ms. Acosta and Mr. Youngblood would be considered independent. Because of their relationships with the Sponsor Group or with EFH Corp. directly, none of the other directors would be considered independent. See “Certain Relationships and Related Party Transactions” and 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 New York Stock Exchange’s independence requirements for issuers of equity securities. We believe that none of the members of EFH Corp.’s Governance and Public Affairs Committee would meet the New York Stock Exchange’s independence requirements for issuers of equity securities. Under the New York Stock Exchange’s audit committee independence requirement for issuers of debt securities, Messrs. Huffines and Youngblood and Ms. Acosta, who constitute the Audit Committee, are considered independent.
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| 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 2009 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 internal audit executive. 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, 2009 and 2008, fees billed to EFH Corp. by Deloitte & Touche were as follows:
| 2009 | 2008 | |||||
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 | $ | 7,549,000 | $ | 7,956,000 | ||
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 | 1,811,000 | 4,923,000 | ||||
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 | 904,000 | 1,777,000 | ||||
All Other Fees.Fees for services including process improvement reviews, forensic accounting reviews, litigation and rate case assistance, and training services | 0 | 0 | ||||
Total | $ | 10,264,000 | $ | 14,656,000 | ||
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| Item 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES |
(a) Oncor Holdings Financial Statements are presented pursuant to Item 3-16 of Regulation S-X as Exhibit 99(d).
(b) Exhibits:
EFH Corp. Exhibits to Form 10-K for the Fiscal Year Ended December 31, 2009
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 (1997) (filed March 27, 1998) | 4(c) | — | Indenture (For Unsecured Debt Securities Series P), dated as of November 1, 2004, between Energy Future Holdings Corp. and The Bank of New York Mellon (formerly known as The Bank of New York). Energy Future Holdings Corp.’s Indentures for its Series Q and R Senior Notes are not being filed as they are substantially similar to this Indenture | ||||
| 4(b) | 1-12833 Form 10-K (2004) (filed March 16, 2005) | 4(q) | — | Officers’ Certificate, dated November 26, 2004, establishing the terms of Energy Future Holdings Corp.’s 5.55% Series P Senior Notes due November 15, 2014 | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 4(c) | 1-12833 Form 10-K (2004) (filed March 16, 2005) | 4(r) | — | Officers’ Certificate, dated November 26, 2004, establishing the terms of Energy Future Holdings Corp.’s 6.50% Series Q Senior Notes due November 15, 2024 | ||||
| 4(d) | 1-12833 Form 10-K (2004) (filed March 16, 2005) | 4(s) | — | Officers’ Certificate, dated November 26, 2004, establishing the terms of Energy Future Holdings Corp.’s 6.55% Series R Senior Notes due November 15, 2034 | ||||
| 4(e) | 1-12833 Form 8-K (filed October 31, 2007) | 4.1 | — | Indenture, dated as of October 31, 2007, relating to Energy Future Holdings Corp.’s 10.875% Senior Notes due 2017 and 11.250%/12.000% Senior Toggle Notes due 2017 | ||||
| 4(f) | — | Supplemental Indenture, dated as of July 8, 2008, to Indenture, dated as of October 31, 2007, relating to Energy Future Holdings Corp.’s 10.875% Senior Notes due 2017 and 11.25%/12.00% Senior Toggle Notes due 2017 | ||||||
| 4(g) | 1-12833 Form 10-Q (Quarter ended June 30, 2009) (filed August 4, 2009) | 4(a) | — | Second Supplemental Indenture, dated as of August 3, 2009, to Indenture, dated as of October 31, 2007, relating to Energy Future Holdings Corp.’s 10.875% Senior Notes due 2017 and 11.25%/12.00% Senior Toggle Notes due 2017 | ||||
| 4(h) | 1-12833 Form 8-K (filed November 20, 2009) | 4.1 | — | Indenture dated as of November 16, 2009, among Energy Future Holdings Corp., the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A. | ||||
| 4(i) | 1-12833 Form 8-K (filed January 19, 2010) | 4.1 | — | Indenture dated as of January 12, 2010, among Energy Future Holdings Corp., the guarantors named therein and The Bank of New York Mellon Trust Company, N.A. | ||||
| 4(j) | 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 | ||||
Oncor Electric Delivery Company LLC | ||||||||
| 4(k) | 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 (formerly Oncor Electric Delivery Company, formerly known as TXU Electric Delivery Company) and The Bank of New York Mellon, as Trustee | ||||
| 4(l) | 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(m) | 333-100240 Form S-4 (filed October 2, 2002) | 4(b) | — | Officer’s Certificate, dated May 6, 2002, establishing the terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes (formerly Senior Secured Notes) due 2012 and 7.000% Senior Notes (formerly Senior Secured Notes) due 2032 | ||||
| 4(n) | 333-106894 Form S-4 (filed July 9, 2003) | 4(c) | — | Officer’s Certificate, dated December 20, 2002, establishing the terms of Oncor Electric Delivery Company LLC’s 6.375% Senior Notes (formerly Senior Secured Notes) due 2015 and 7.250% Senior Notes (formerly Senior Secured Notes) due 2033 | ||||
| 4(o) | 333-100242 Form S-4 (filed October 2, 2002) | 4(a) | — | Indenture (for Unsecured Debt Securities), dated as of August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York Mellon, as Trustee | ||||
| 4(p) | 333-100242 Form S-4 (filed October 2, 2002) | 4(b) | — | Officer’s Certificate, dated August 30, 2002, establishing the terms of Oncor Electric Delivery Company LLC’s 7.00% Debentures due 2022 | ||||
| 4(q) | 333-100242 Form 8-K (filed September 9, 2008) | 4.1 | — | Officer’s Certificate, dated September 8, 2008, establishing the terms of Oncor’s 5.95% Senior Secured Notes due 2013, 6.80% Senior Secured Notes due 2018 and 7.50% Senior Secured Notes due 2038 | ||||
| 4(r) | 333-100240 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008) | 4(b) | — | Supplemental Indenture No. 2, dated May 15, 2008, to Indenture and Deed of Trust, dated as of May 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York. | ||||
| 4(s) | 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 as of August 1, 2002, between Oncor Electric Delivery Company LLC and The Bank of New York. | ||||
| 4(t) | 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, as Collateral Agent. | ||||
| 4(u) | 333-100240 Form 10-K (2008) (filed March 2, 2009) | 4(n) | — | First Amendment to Deed of Trust, dated as of March 2, 2009, by and between Oncor Electric Delivery Company LLC and The Bank of New York Mellon (formerly The Bank of New York) as Trustee and Collateral Agent. | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
Texas Competitive Electric Holdings Company LLC | ||||||||
| 4(v) | 333-108876 Form 8-K (filed October 31, 2007) | 4.2 | — | Indenture, dated as of October 31, 2007, relating to Texas Competitive Electric Holdings Company LLC’s and TCEH Finance, Inc.’s 10.25% Senior Notes due 2015 | ||||
| 4(w) | 1-12833 Form 8-K (filed December 12, 2007) | 4.1 | — | First Supplemental Indenture, dated as of December 6, 2007, to Indenture, dated as of 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(x) | 1-12833 Form 10-Q (Quarter ended June 30, 2009) (filed August 4, 2009) | 4(b) | — | Second Supplemental Indenture, dated as of August 3, 2009, to Indenture, dated as of 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 | ||||
Energy Future Intermediate Holding Company LLC | ||||||||
| 4(y) | 1-12833 Form 8-K (filed November 20, 2009) | 4.2 | — | Indenture, dated as of November 16, 2009, among Energy Future Intermediate Holding Company LLC and EFIH Finance Inc. and The Bank of New York Mellon Trust Company, N.A. | ||||
| 4(z) | 1-12833 Form 8-K (filed November 20, 2009) | 4.3 | — | Pledge Agreement, dated as of November 16, 2009, by Energy Future Intermediate Holding Company LLC | ||||
| 4(aa) | 1-12833 Form 8-K (filed November 20, 2009) | 4.4 | — | Collateral Trust Agreement, dated as of November 16, 2009, among Energy Future Intermediate Holding Company LLC, The Bank of New York Mellon Trust Company, N.A, as First Lien Trustee, the other Secured Debt named therein and The Bank of New York Mellon Trust Company N.A., as Collateral Trustee | ||||
| (10) | Material Contracts | |||||||
Management Contracts; Compensatory Plans, Contracts and Arrangements | ||||||||
| 10(a) | 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(b) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(b) | — | Registration Rights Agreement by and among Texas Energy Future Holdings Limited Partnership, Energy Future Holdings Corp. and the stockholders party thereto | ||||
| 10(c) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(f) | — | Energy Future Holdings Corp. Non-employee Director Compensation Arrangements | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 10(d) | 1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008) | 10(a) | — | Form of Stockholder’s Agreement (for Directors), by and among Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and the stockholder party thereto | ||||
| 10(e) | 1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008) | 10(b) | — | Form of Sale Participation Agreement (for Directors), by and between Texas Energy Future Holdings Limited Partnership and the stockholder party hereto | ||||
| 10(f) | 1-12833 Form 10-K (2008) (filed March 3, 2009) | 10(i) | — | EFH Executive Annual Incentive Plan, as amended and restated, effective as of January 1, 2008 | ||||
| 10(g) | 1-12833 Form 8-K (filed May 23, 2005) | 10.7 | — | Energy Future Holdings Corp. 2005 Executive Severance Plan | ||||
| 10(h) | 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 Description | ||||
| 10(i) | 1-12833 Form 8-K (filed May 23, 2005) | 10.6 | — | Energy Future Holdings Corp. Executive Change in Control Policy | ||||
| 10(j) | 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 | ||||
| 10(k) | 1-12833 Form 10-K (2008) (filed March 3, 2009) | 10(q) | — | EFH Second Supplemental Retirement Plan, as amended and restated, effective as of October 10, 2007 | ||||
| 10(l) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(p) | — | Employment Agreement, dated January 6, 2008, by and between John F. Young and Energy Future Holdings Corp. | ||||
| 10(m) | — | Form of Amended and Restated Non-Qualified Stock Option Agreement (For Executive Officers) | ||||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 10(n) | 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) | ||||
| 10(o) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(r) | — | Management Stockholder’s Agreement, dated as of February 1, 2008, by and among John F. Young, Texas Energy Future Holdings Limited Partnership and Energy Future Holdings Corp. | ||||
| 10(p) | 1-12833 Form 10-Q (Quarter ended June 30, 2008) (filed August 14, 2008) | 10(g) | — | Form of Sale Participation Agreement (For Executive Officers) | ||||
| 10(q) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(s) | — | Sale Participation Agreement, dated as of February 1, 2008, by and between John F. Young and Texas Energy Future Holdings Limited Partnership | ||||
| 10(r) | 1-12833 Form 10-K (2008) (filed March 3, 2009) | 10(y) | — | Amended and Restated Employment Agreement, dated as of July 1, 2008, by and between Paul M. Keglevic and Energy Future Holdings Corp. | ||||
| 10(s) | 1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008) | 10(g) | — | Employment Agreement, dated May 9, 2008, by and among David Campbell, Energy Future Holdings Corp. and Luminant Holding Company LLC | ||||
| 10(t) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(y) | — | Additional Payment Agreement, dated October 10, 2007, by and among David Campbell, Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and Texas Competitive Electric Holdings Company LLC | ||||
| 10(u) | 1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008) | 10(h) | — | Employment Agreement, dated May 9, 2008, by and between Rob Walters and Energy Future Holdings Corp. | ||||
| 10(v) | 1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008) | 10(p) | — | Amended and Restated Employment Agreement, dated May 9, 2008, by and among James Burke, Energy Future Holdings Corp. and TXU Energy Retail Company LLC | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 10(w) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(ff) | — | Additional Payment Agreement, dated October 10, 2007, by and among James Burke, Energy Future Holdings Corp., Texas Energy Future Holdings Limited Partnership and Texas Competitive Electric Holdings Company LLC | ||||
| 10(x) | 1-12833 Form 10-Q (Quarter ended March 31, 2008) (filed May 15, 2008) | 10(k) | — | Employment Agreement, dated May 9, 2008, by and among Charles R. Enze, Energy Future Holdings Corp. and Luminant Holding Company LLC | ||||
| 10(y) | 1-12833 Form 10-K (2008) (filed March 3, 2009) | 10(ii) | — | Amended and Restated Employment Agreement, dated July 7, 2008, by and between Luminant Holding Company LLC, Energy Future Holdings Corp. and Mark Allen McFarland | ||||
| 10(z) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(nn) | — | Deferred Share Agreement, dated October 9, 2007, by and between James Burke and Texas Energy Future Holdings Limited Partnership | ||||
| 10(aa) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(oo) | — | Deferred Share Agreement, dated October 9, 2007, by and between Charles Enze and Texas Energy Future Holdings Limited Partnership | ||||
| 10(bb) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(qq) | — | Deferred Share Agreement, dated October 9, 2007, by and between Michael Greene and Texas Energy Future Holdings Limited Partnership | ||||
| 10(cc) | — | Severance and Release Agreement dated October 5, 2009, by and between Energy Future Holdings Corp. and M. Rizwan Chand | ||||||
| 10(dd) | — | EFH Salary Deferral Program, as amended and restated, effective January 1, 2010 | ||||||
| 10(ee) | — | Amendment to EFH Second Supplemental Retirement Plan, dated July 31, 2009 | ||||||
| 10(ff) | — | Stock Option Agreement, dated as of December 17, 2009, by and between Joel Kaplan and Energy Future Holdings Corp. | ||||||
| 10(gg) | — | Stock Option Agreement, dated as of January 26, 2010, by and between Richard Landy and Energy Future Holdings Corp. | ||||||
| 10(hh) | — | Restricted Stock Unit Award Agreement, effective as of January 6, 2008, between John F. Young and Energy Future Holdings Corp. | ||||||
| 10(ii) | — | Amendment No. 1 to the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its affiliates | ||||||
| 10(jj) | — | Employment Arrangement with John Young | ||||||
| 10(kk) | — | Employment Arrangement with Certain Executive Officers | ||||||
| 10(ll) | — | Employment Arrangement with Joel D. Kaplan | ||||||
| 10(mm) | — | Employment Arrangement with Richard J. Landy | ||||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 10(nn) | — | Consulting Agreement dated as of February 18, 2010 between Energy Future Holdings Corp. and Donald Evans | ||||||
| 10(oo) | — | Amended and Restated Non-Qualified Stock Option Agreement dated as of December 1, 2009 between Charles R. Enze and Energy Future Holdings Corp. | ||||||
Credit Agreements | ||||||||
| 10(pp) | 1-12833 Form 10-Q (Quarter ended September 30, 2007) (filed November 14, 2007) | 10.C | — | $24,500,000,000 Credit Agreement, dated as of 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, J. Aron & Company, as posting calculation agent, JPMorgan Chase Bank, N.A., as syndication agent and revolving letter of credit issuer, Credit Suisse, Goldman Sachs Credit Partners L.P., Lehman Commercial Paper Inc. and Morgan Stanley Senior Funding, Inc., as co-documentation agents, 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, and Goldman Sachs Credit Partners L.P., as posting lead arranger and bookrunner | ||||
| 10(qq) | 1-12833 Form 8-K (filed August 10, 2009) | 10.1 | — | Amendment No. 1, dated as of August 7, 2009, to the $24,500,000,000 Credit Agreement dated as of October 10, 2007 among Energy Future Competitive Holdings Company, Texas Competitive Electric Holdings Company LLC, as the Borrower, Citibank, N.A., as Administrative Agent, Goldman Sachs Credit Partners L.P. as Posting Agent, J. Aron & Company, as Posting Calculation Agent and the several lenders thereto from time to time | ||||
| 10(rr) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(ss) | — | Guarantee Agreement, dated as of 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 | ||||
| 10(ss) | 1-12833 Form 8-K (filed August 10, 2009) | 10.4 | — | Amended and Restated Pledge Agreement, dated as of 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 of the secured parties under the $24,500,000,000 Credit Agreement | ||||
| 10(tt) | 1-12833 Form 8-K (filed August 10, 2009) | 10.3 | — | Amended and Restated Security Agreement, dated as of 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 grantors party thereto, and Citibank, N.A., as collateral agent for the benefit of the secured parties under the $24,500,000,000 Credit Agreement | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 10(uu) | 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(vv) | 1-12833 Form 8-K (filed August 10, 2009) | 10.2 | — | Amended and Restated Collateral Agency and Intercreditor Agreement, dated as of 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, Lehman Brothers Commodity Services Inc., J. Aron & Company, Morgan Stanley Capital Group Inc., Citigroup energy Inc., and each other secured commodity hedge counterparty from time to time party thereto, and any other person that becomes a secured party pursuant thereto | ||||
| 10(ww) | 333-100240 Form 10-Q (Quarter ended September 30, 2007) (filed November 14, 2007) | 10.A | — | $2,000,000,000 Revolving Credit Agreement, dated as of 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 | ||||
Other Material Contracts | ||||||||
| 10(xx) | 333-100240 Form 8-K (filed August 13, 2008) | 10.1 | — | Contribution and Subscription Agreement, dated as of August 12, 2008, by and between Oncor and Texas Transmission Investment LLC | ||||
| 10(yy) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(eee) | — | Stipulation as approved by the PUC in Docket No. 34077 | ||||
| 10(zz) | 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(aaa) | 1-12833 Form 10-K (2003) (filed March 15, 2004) | 10(qq) | — | Lease Agreement, dated as of February 14, 2002, between State Street Bank and Trust Company of Connecticut, National Association, as owner trustee of ZSF/Dallas Tower Trust, a Delaware grantor trust, as Lessor and EFH Properties Company, a Texas corporation, as Lessee (Energy Plaza Property) | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 10(bbb) | 1-12833 Form 10-Q (Quarter ended June 30, 2007) (filed August 9, 2007) | 10.1 | — | First Amendment to Lease Agreement, dated as of June 1, 2007, between U.S. Bank, N.A. (as successor-in-interest to State Street Bank and Trust Company of Connecticut, National Association), as owner trustee of ZSF/Dallas Tower Trust, a Delaware grantor trust, as Lessor, and EFH Properties Company, a Texas corporation, as Lessee (Energy Plaza Property) | ||||
| 10(ccc) | 1-12833 Form 10-Q (Quarter ended June 30, 2007) (filed August 9, 2007) | 10.2 | — | Amended and Restated Engineering, Procurement and Construction Agreement, dated as of June 8, 2007, between Oak Grove Management Company LLC, a Delaware limited liability company and a wholly-owned, direct subsidiary of Texas Competitive Holdings Company LLC, and Fluor Enterprises, Inc., a California corporation (confidential treatment has been requested for portions of this exhibit) | ||||
| 10(ddd) | 1-12833 Form 10-Q (Quarter ended September 30, 2007) (filed November 14, 2007) | 10.B | — | Engineering, Procurement and Construction Agreement, dated as of May 26, 2006, between Texas Competitive Electric Holdings Company LLC (as successor-in-interest to EFC Holdings) and Bechtel Power Corporation (confidential treatment has been requested for portions of this exhibit) | ||||
| 10(eee) | 1-12833 Form 10-K (2006) (filed March 2, 2007) | 10(iii) | — | Amended and Restated Transaction Confirmation by Generation Development Company LLC (formerly known as TXU 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 (2006) (filed March 2, 2007) | 10(jjj) | — | 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(ggg) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(sss) | — | ISDA Master Agreement, dated as of October 25, 2007, between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P. | ||||
| 10(hhh) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(ttt) | — | Schedule to the ISDA Master Agreement, dated as of October 25, 2007, between Texas Competitive Electric Holdings Company LLC and Goldman Sachs Capital Markets, L.P. | ||||
| 10(iii) | 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(jjj) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(vvv) | — | ISDA Master Agreement, dated as of October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International | ||||
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Exhibits | Previously Filed* With File Number | As Exhibit | ||||||
| 10(kkk) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(www) | — | Schedule to the ISDA Master Agreement, dated as of October 29, 2007, between Texas Competitive Electric Holdings Company LLC and Credit Suisse International | ||||
| 10(lll) | 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(mmm) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(yyy) | — | Management Agreement, dated as of 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(nnn) | 333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008) | 3(a) | — | Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Company LLC, dated as of November 5, 2008 | ||||
| 10(ooo) | 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 as of November 5, 2008 | ||||
| 10(ppp) | 333-100240 Form 10-K (2008) (filed March 3, 2009) | 3(c) | — | First Amendment to Second Amended and Restated Limited Liability Company Agreement of Oncor Electric Delivery Company LLC, entered into as of February 18, 2009, by and among Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Oncor Management Investment LLC | ||||
| 10(qqq) | 333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008) | 4(c) | — | Investor Rights Agreement, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp. | ||||
| 10(rrr) | 333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008) | 4(d) | — | Registration Rights Agreement of Oncor Electric Delivery Company LLC, dated as of November 5, 2008, by and among Oncor Electric Delivery Company LLC, Oncor Electric Delivery Holdings Company LLC, Texas Transmission Investment LLC and Energy Future Holdings Corp. | ||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 10(sss) | 333-100240 Form 10-Q (Quarter ended September 30, 2008) (filed November 6, 2008) | 10(b) | — | Amended and Restated Tax Sharing Agreement, dated as of November 5, 2008, by and 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. | ||||
| 10(ttt) | 1-12833 Form 10-K (2007) (filed March 31, 2008) | 10(cccc) | — | Indemnification Agreement, dated as of 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(uuu) | 333-100240 Form 10-K (2004) (filed March 23, 2005) | 10(i) | — | Agreement, dated as of March 10, 2005, by and 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. | ||||
| (12) | Statement Regarding Computation of Ratios | |||||||
| 12(a) | — | Computation of Ratio of Earnings to Fixed Charges, and Ratio of Earnings to Combined Fixed Charges and Preference Dividends | ||||||
| (18) | Letter re Change in Accounting Principles | |||||||
| 18(a) | — | EFH Corp. Preferability Letter | ||||||
| 18(b) | — | Oncor Holdings Preferability Letter | ||||||
| (21) | Subsidiaries of the Registrant | |||||||
| 21(a) | — | Subsidiaries of Energy Future Holdings Corp. | ||||||
| (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 | ||||||
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Exhibits | Previously Filed* With File Number | As | ||||||
| 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) | Post-Effective Amendment No. 1 to 33-55408 Form S-3 (filed July, 1993) | 99(b) | — | Amended Agreement dated as of January 30, 1990, between Energy Future Competitive Holdings Company (formerly known as Texas Utilities Electric 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, 2009 and 2008 | ||||||
| 99(c) | — | TCEH Consolidated Adjusted EBITDA reconciliation for the years ended December 31, 2009 and 2008 | ||||||
| 99(d) | — | Oncor Electric Delivery Holdings Company LLC financial statements presented pursuant to Item 3-16 of Regulation S-X. | ||||||
| * | Incorporated herein by reference |
| ** | Certain instruments defining the rights of holders of long-term debt of the registrant’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 registrant and its subsidiaries on a consolidated basis. Registrant 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 18, 2010 | 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 Officer and Director | February 18, 2010 | ||
| (John F. Young, President and Chief Executive Officer) | ||||
/s/ PAUL M. KEGLEVIC | Principal Financial Officer | February 18, 2010 | ||
| (Paul M. Keglevic, Executive Vice President and Chief Financial Officer) | ||||
/s/ STANLEY J. SZLAUDERBACH | Principal Accounting Officer | February 18, 2010 | ||
| (Stanley J. Szlauderbach, Senior Vice President and Controller) | ||||
/s/ DONALD L. EVANS | Director | February 18, 2010 | ||
| (Donald L. Evans, Chairman of the Board) | ||||
/s/ ARCILIA C. ACOSTA | Director | February 18, 2010 | ||
| (Arcilia C. Acosta) | ||||
/s/ DAVID BONDERMAN | Director | February 18, 2010 | ||
| (David Bonderman) | ||||
/s/ THOMAS D. FERGUSON | Director | February 18, 2010 | ||
| (Thomas D. Ferguson) | ||||
/s/ FREDERICK M. GOLTZ | Director | February 18, 2010 | ||
| (Frederick M. Goltz) | ||||
/s/ JAMES R. HUFFINES | Director | February 18, 2010 | ||
| (James R. Huffines) | ||||
/s/ SCOTT LEBOVITZ | Director | February 18, 2010 | ||
| (Scott Lebovitz) | ||||
/s/ JEFFREY LIAW | Director | February 18, 2010 | ||
| (Jeffrey Liaw) | ||||
/s/ MARC S. LIPSCHULTZ | Director | February 18, 2010 | ||
| (Marc S. Lipschultz) | ||||
/s/ MICHAEL MACDOUGALL | Director | February 18, 2010 | ||
| (Michael MacDougall) | ||||
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Signature | Title | Date | ||
/s/ LYNDON L. OLSON, JR. | Director | February 18, 2010 | ||
| (Lyndon L. Olson, Jr.) | ||||
/s/ KENNETH PONTARELLI | Director | February 18, 2010 | ||
| (Kenneth Pontarelli) | ||||
/s/ WILLIAM K. REILLY | Director | February 18, 2010 | ||
| (William K. Reilly) | ||||
/s/ JONATHAN D. SMIDT | Director | February 18, 2010 | ||
| (Jonathan D. Smidt) | ||||
/s/ KNEELAND YOUNGBLOOD | Director | February 18, 2010 | ||
| (Kneeland Youngblood) | ||||
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Exhibit 4(f)
SUPPLEMENTAL INDENTURE
Supplemental Indenture (this “Supplemental Indenture”), dated as of July 8, 2008, between Energy Future Intermediate Holding Company LLC (formerly known as InfrastruX Energy Services BPL LLC), a Delaware limited liability company (the “New Guaranteeing Subsidiary”), a subsidiary of Energy Future Holdings Corp. (the “Issuer”), and The Bank of New York Mellon (formerly known as The Bank of New York), as trustee (the “Trustee”).
W I T N E S S E T H
WHEREAS, each of the Issuer and the Guarantors (as defined in the Indenture referred to below) has heretofore executed and delivered to the Trustee an Indenture (the “Indenture”), dated as of October 31, 2007, providing for the issuance of an unlimited aggregate principal amount of 10.875% Senior Notes due 2017 and 11.250%/12.000% Senior Toggle Notes due 2017 (together, the “Senior Notes”);
WHEREAS, Energy Future Intermediate Holding Company LLC, a Delaware limited liability company (the “Old Guarantor”), was merged with and into the New Guaranteeing Subsidiary, which successor entity, pursuant to Section 5.01(c)(1)(B) of the Indenture, has assumed all of the obligations of the Old Guarantor under the Indenture and the Old Guarantor’s related Guarantee;
WHEREAS, the Indenture provides that under certain circumstances the New Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the New Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuer’s Obligations under the Senior Notes and the Indenture on the terms and conditions set forth herein and under the Indenture (the “Guarantee”); and
WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.
NOW THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the parties mutually covenant and agree for the equal and ratable benefit of the Holders of the Senior Notes as follows:
1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.
2.ASSUMPTIONOFTHEINDENTUREANDTHEGUARANTEE. The New Guaranteeing Subsidiary, as the successor entity in the above-referenced merger, hereby assumes the Old Guarantor’s obligations under the Indenture and the Guarantee.
3. AGREEMENTTO GUARANTEE. The New Guaranteeing Subsidiary hereby agrees as follows:
(a) Along with all Guarantors named in the Indenture, to jointly and severally unconditionally guarantee to each Holder of a Senior Note authenticated and delivered by the Trustee and to the Trustee and its successors and assigns, irrespective of the validity and enforceability of the Indenture, the Senior Notes or the obligations of the Issuer hereunder or thereunder, that:
(i) the principal of and interest, premium and Additional Interest, if any, on the Senior Notes will be promptly paid in full when due, whether at maturity, by acceleration, redemption or otherwise, and interest on the overdue principal of and interest on the Senior Notes, if any, if lawful, and all other obligations of the Issuer to the Holders or the Trustee hereunder or thereunder will be promptly paid in full or performed, all in accordance with the terms hereof and thereof; and
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(ii) in case of any extension of time of payment or renewal of any Senior Notes or any of such other obligations, that same will be promptly paid in full when due or performed in accordance with the terms of the extension or renewal, whether at stated maturity, by acceleration or otherwise. Failing payment when due of any amount so guaranteed or any performance so guaranteed for whatever reason, the Guarantors and the New Guaranteeing Subsidiary shall be jointly and severally obligated to pay the same immediately. This is a guarantee of payment and not a guarantee of collection.
(b) The obligations hereunder shall be unconditional, irrespective of the validity, regularity or enforceability of the Senior Notes or the Indenture, the absence of any action to enforce the same, any waiver or consent by any Holder of the Senior Notes with respect to any provisions hereof or thereof, the recovery of any judgment against the Issuer, any action to enforce the same or any other circumstance which might otherwise constitute a legal or equitable discharge or defense of a guarantor.
(c) The following is hereby waived: diligence, presentment, demand of payment, filing of claims with a court in the event of insolvency or bankruptcy of the Issuer, any right to require a proceeding first against the Issuer, protest, notice and all demands whatsoever.
(d) Except as set forth in Section 6 hereto, this Guarantee shall not be discharged except by complete performance of the obligations contained in the Senior Notes, the Indenture and this Supplemental Indenture, and the New Guaranteeing Subsidiary accepts all obligations of a Guarantor under the Indenture.
(e) If any Holder or the Trustee is required by any court or otherwise to return to the Issuer, the Guarantors (including the New Guaranteeing Subsidiary), or any custodian, trustee, liquidator or other similar official acting in relation to either the Issuer or the Guarantors, any amount paid either to the Trustee or such Holder, this Guarantee, to the extent theretofore discharged, shall be reinstated in full force and effect.
(f) The New Guaranteeing Subsidiary shall not be entitled to any right of subrogation in relation to the Holders in respect of any obligations guaranteed hereby until payment in full of all obligations guaranteed hereby.
(g) As between the New Guaranteeing Subsidiary, on the one hand, and the Holders and the Trustee, on the other hand, (x) the maturity of the obligations guaranteed hereby may be accelerated as provided in Article 6 of the Indenture for the purposes of this Guarantee, notwithstanding any stay, injunction or other prohibition preventing such acceleration in respect of the obligations guaranteed hereby, and (y) in the event of any declaration of acceleration of such obligations as provided in Article 6 of the Indenture, such obligations (whether or not due and payable) shall forthwith become due and payable by the New Guaranteeing Subsidiary for the purpose of this Guarantee.
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(h) The New Guaranteeing Subsidiary shall have the right to seek contribution from any non-paying Guarantor so long as the exercise of such right does not impair the rights of the Holders under this Guarantee.
(i) Pursuant to Section 10.02 of the Indenture, after giving effect to all other contingent and fixed liabilities that are relevant under any applicable Bankruptcy or fraudulent conveyance laws, and after giving effect to any collections from, rights to receive contribution from or payments made by or on behalf of any other Guarantor in respect of the obligations of such other Guarantor under Article 10 of the Indenture, this new Guarantee shall be limited to the maximum amount permissible such that the obligations of such New Guaranteeing Subsidiary under this Guarantee will not constitute a fraudulent transfer or conveyance.
(j) This Guarantee shall remain in full force and effect and continue to be effective should any petition be filed by or against the Issuer for liquidation, reorganization, should the Issuer become insolvent or make an assignment for the benefit of creditors or should a receiver or trustee be appointed for all or any significant part of the Issuer’s assets, and shall, to the fullest extent permitted by law, continue to be effective or be reinstated, as the case may be, if at any time payment and performance of the Senior Notes are, pursuant to applicable law, rescinded or reduced in amount, or must otherwise be restored or returned by any obligee on the Senior Notes and Guarantee, whether as a “voidable preference”, “fraudulent transfer” or otherwise, all as though such payment or performance had not been made. In the event that any payment or any part thereof, is rescinded, reduced, restored or returned, the Senior Note shall, to the fullest extent permitted by law, be reinstated and deemed reduced only by such amount paid and not so rescinded, reduced, restored or returned.
(k) In case any provision of this Guarantee 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.
(l) This Guarantee shall be a general senior unsecured obligation of such New Guaranteeing Subsidiary, ranking equally in right of payment with all existing and future Senior Indebtedness of the New Guaranteeing Subsidiary, will be effectively subordinated to all Secured Indebtedness of such New Guaranteeing Subsidiary to the extent of the value of the collateral securing such indebtedness. The Guarantees will be senior in right of payment to all existing and future Subordinated Indebtedness of each Guarantor. The Senior Notes will be structurally subordinated to Indebtedness and other liabilities of Subsidiaries of the Issuer that do not Guarantee the Senior Notes, if any.
(m) Each payment to be made by the New Guaranteeing Subsidiary in respect of this Guarantee shall be made without set-off, counterclaim, reduction or diminution of any kind or nature.
4. EXECUTION AND DELIVERY. The New Guaranteeing Subsidiary agrees that the Guarantee shall remain in full force and effect notwithstanding the absence of the endorsement of any notation of such Guarantee on the Senior Notes.
5. MERGER, CONSOLIDATIONOR SALEOF ALLOR SUBSTANTIALLY ALL ASSETS.
(a) Except as otherwise provided in Section 5.01(c) of the Indenture, the New Guaranteeing Subsidiary may not consolidate or merge with or into or wind up into (whether or not the Issuer or New Guaranteeing Subsidiary is the surviving corporation), or sell, assign, transfer, lease, convey or otherwise dispose of all or substantially all of its properties or assets, in one or more related transactions, to any Person unless:
(i) (A) the New Guaranteeing Subsidiary is the surviving corporation or the Person formed by or surviving any such consolidation or merger (if other than the New Guaranteeing Subsidiary) or to which such sale, assignment, transfer, lease, conveyance or other disposition will have been made is a corporation, partnership, limited partnership, limited liability partnership, limited liability corporation or trust organized or existing under the laws of the jurisdiction of organization of the New Guaranteeing Subsidiary, as the case may be, or the laws of the United States, any state thereof, the District of Columbia, or any territory thereof (the New Guaranteeing Subsidiary or such Person, as the case may be, being herein called the “Successor Person”);
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(B) the Successor Person, if other than the New Guaranteeing Subsidiary, expressly assumes all the obligations of the New Guaranteeing Subsidiary under the Indenture and the Registration Rights Agreement and the New Guaranteeing Subsidiary’s related Guarantee pursuant to supplemental indentures or other documents or instruments in form reasonably satisfactory to the Trustee;
(C) immediately after such transaction, no Default exists; and
(D) the Issuer shall have delivered to the Trustee an Officer’s Certificate and an Opinion of Counsel, each stating that such consolidation, merger or transfer and such supplemental indentures, if any, comply with the Indenture; or
(ii) the transaction is made in compliance with Section 4.10 of the Indenture;
(b) Subject to certain limitations described in the Indenture, the Successor Person will succeed to, and be substituted for, the New Guaranteeing Subsidiary under the Indenture and the New Guaranteeing Subsidiary’s Guarantee. Notwithstanding the foregoing, the New Guaranteeing Subsidiary may (i) merge into or transfer all or part of its properties and assets to another Guarantor or the Issuer, (ii) merge with an Affiliate of the Issuer solely for the purpose of reincorporating the New Guaranteeing Subsidiary in the United States, any state thereof, the District of Columbia or any territory thereof or (iii) convert into a corporation, partnership, limited partnership, limited liability corporation or trust organized or existing under the laws of the jurisdiction of organization of such Guarantor.
6. RELEASES. The Guarantee of the New Guaranteeing Subsidiary shall be automatically and unconditionally released and discharged, and no further action by the New Guaranteeing Subsidiary, the Issuer or the Trustee is required for the release of the New Guaranteeing Subsidiary’s Guarantee, upon:
(1) (A) any sale, exchange or transfer (by merger or otherwise) of the Capital Stock of the New Guaranteeing Subsidiary (including any sale, exchange or transfer), after which the New Guaranteeing Subsidiary is no longer a Restricted Subsidiary or all or substantially all the assets of the New Guaranteeing Subsidiary which sale, exchange or transfer is made in compliance with the applicable provisions of the Indenture;
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(B) the release or discharge of the guarantee by the New Guaranteeing Subsidiary of the guarantee which resulted in the creation of the Guarantee, except a discharge or release by or as a result of payment under such guarantee;
(C) the proper designation of the New Guaranteeing Subsidiary as an Unrestricted Subsidiary in compliance with Section 4.08 of the Indenture; or
(D) the Issuer exercising its Legal Defeasance option or Covenant Defeasance option in accordance with Article 8 of the Indenture or the Issuer’s obligations under the Indenture being discharged in accordance with the terms of the Indenture; and
(2) the New Guaranteeing Subsidiary delivering to the Trustee an Officer’s Certificate and an Opinion of Counsel, each stating that all conditions precedent provided for in the Indenture relating to such transaction have been complied with.
7. NO RECOURSE AGAINST OTHERS. No director, officer, employee, incorporator or stockholder of the New Guaranteeing Subsidiary shall have any liability for any obligations of the Issuer or the Guarantors (including the New Guaranteeing Subsidiary) under the Senior Notes, any Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each Holder by accepting Senior Notes waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Senior Notes.
8. GOVERNING LAW. THIS SUPPLEMENTAL INDENTURE WILL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK.
9. COUNTERPARTS. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement.
10. EFFECTOF HEADINGS. The Section headings herein are for convenience only and shall not affect the construction hereof.
11. THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the New Guaranteeing Subsidiary.
12. SUBROGATION. The New Guaranteeing Subsidiary shall be subrogated to all rights of Holders of Senior Notes against the Issuer in respect of any amounts paid by the New Guaranteeing Subsidiary pursuant to the provisions of Section 3 hereof and Section 10.01 of the Indenture;provided that if an Event of Default has occurred and is continuing, the New Guaranteeing Subsidiary shall not be entitled to enforce or receive any payments arising out of, or based upon, such right of subrogation until all amounts then due and payable by the Issuer under the Indenture or the Senior Notes shall have been paid in full.
13. BENEFITS ACKNOWLEDGED. The New Guaranteeing Subsidiary’s Guarantee is subject to the terms and conditions set forth in the Indenture. The New Guaranteeing Subsidiary acknowledges that it will receive direct and indirect benefits from the financing arrangements contemplated by the Indenture and this Supplemental Indenture and that the guarantee and waivers made by it pursuant to this Guarantee are knowingly made in contemplation of such benefits.
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14. SUCCESSORS. All agreements of the New Guaranteeing Subsidiary in this Supplemental Indenture shall bind its Successors, except as otherwise provided in Section 3(k) hereof or elsewhere in this Supplemental Indenture. All agreements of the Trustee in this Supplemental Indenture shall bind its successors.
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IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed, all as of the date first above written.
| THE BANK OF NEW YORK MELLON (FORMERLY KNOWN AS THE BANK OF NEW YORK), as Trustee | ||||
| By: | /s/ Remo Reale | |||
| Name: | Remo J. Reale | |||
| Title: | Vice President | |||
| ENERGY FUTURE INTERMEDIATE HOLDING COMPANY LLC (FORMERLY KNOWN AS INFRASTRUX ENERGY SERVICES BPL LLC) | ||||
| By: | /s/ Anthony R. Horton | |||
| Name: | Anthony R. Horton | |||
| Title: | Senior Vice President and Treasurer | |||
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Exhibit 10(m)
ENERGY FUTURE HOLDINGS CORP. KEY EMPLOYEE
FORM OF AMENDED AND RESTATED NON-QUALIFIED STOCK OPTION AGREEMENT
[For Executive Officers]
THIS AMENDED AND RESTATED NON-QUALIFIED STOCK OPTION AGREEMENT (“Agreement”), dated as of , 2009 (the “Effective Date”), is made by and between Energy Future Holdings Corp., a Texas corporation (hereinafter referred to as the “Company”), and the individual whose name is set forth on the signature page hereof (hereinafter referred to as the “Optionee”). Any capitalized terms used but not otherwise defined herein shall have the meaning set forth in the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates or any successor plan (the “Plan”).
WHEREAS, the Organization and Compensation Committee of the Board of the Company (the “Committee”) has determined that it would be to the advantage and best interest of the Company and its shareholders to grant the Option provided for herein to the Optionee as an incentive for increased efforts during his term of employment with the Company or its Subsidiaries or Affiliates, and has advised the Company thereof and authorized the undersigned officers to issue said Option;
WHEREAS, the Company wishes to act consistently with the Plan, the terms of which are hereby incorporated by reference and made part of this Agreement; and
WHEREAS, the parties previously entered into a Non-Qualified Stock Option Agreement, dated , 2008 (“Original Option Agreement”), pursuant to which the Company granted stock options to the Optionee, and the parties desire to enter into this Agreement to (i) reduce the number of performance-related options subject to the award, and (ii) grant additional time-based vesting options on the terms and conditions set forth herein.
NOW, THEREFORE, in consideration of the mutual covenants herein contained and other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereto do hereby agree as follows:
ARTICLE I
DEFINITIONS
Whenever the following terms are used in this Agreement, they shall have the meaning specified below unless the context clearly indicates to the contrary.
Section 1.1Cause
“Cause” shall mean “Cause” as defined in the employment agreement or change-in-control agreement between the Optionee and the Company or any of its Subsidiaries or Affiliates or, if there is no such employment or change-in-control agreement in effect at the time Optionee’s employment is terminated, “Cause” shall mean, with respect to an Optionee: (i) if, in carrying out his duties to the Company, the Optionee engages in conduct that constitutes (a) a material breach of his fiduciary duty to the Company or its shareholders (including, without limitation a material breach or attempted breach of the restrictive covenants under the Management Stockholder’s Agreement), (b) gross neglect or (c) gross misconduct resulting in material economic harm to the Company, provided that any such conduct described in (a), (b) or (c) is not cured within ten (10) business days after the Optionee receives from the Company written notice thereof, or (ii) Optionee’s conviction of, or entry of a plea of guilty or nolo contendere for, a felony or other crime involving moral turpitude.
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Section 1.2Cliff Vesting Option
“Cliff Vesting Option” shall have the meaning given such term in Section 2.1 hereof.
Section 1.3Closing Date
“Closing Date” shall mean October 10, 2007.
Section 1.4Disability
“Disability” shall mean “Disability” as defined in the employment agreement between the Optionee and the Company or any of its Subsidiaries, or, if there is no such employment agreement, “Disability” shall mean the Optionee’s physical or mental incapacitation and consequent inability for a period of six consecutive months to perform the Optionee’s duties;provided,however, in the event the Company temporarily replaces the Optionee or transfers the Optionee’s duties or responsibilities to another individual on account of the Optionee’s mental or physical impairment for a period of time which is covered by the Company’s short term disability plan, the Optionee’s employment shall not be deemed terminated by the Company and the Optionee shall not be able to resign with Good Reason.
Section 1.5Extended Exercise Date
“Extended Exercise Date” shall mean the earlier of: (i) the tenth anniversary of the applicable Grant Date; or (ii) the later of the date: (A) one hundred and eighty (180) days following the date an Optionee’s employment with the Company and all Service Recipients is terminated and (B) thirty (30) days following the first date on which the Optionee could exercise the Option, or any portion thereof, and immediately resell the Shares acquired upon such exercise for cash consideration.
Section 1.6Fair Market Value
“Fair Market Value” shall mean, for the purposes of the Plan and this Agreement and notwithstanding the definition contained in the Plan: (i) if there is a public market for the Shares on such date, the average of the high and low closing bid prices of the Shares on such stock exchange on which the Shares are principally trading on the date in question, or, if there were no sales on such date, on the closest preceding date on which there were sales of Shares or, (ii) if there is no public market for the Shares, on a per Share basis, the fair market value of the Shares on any given date, as determined reasonably and in good faith by the Board, which shall not take into account any minority interest discount or a discount for illiquidity of Shares held by an Optionee in excess of any illiquidity discount applicable to Shares generally; provided that if the Board’s determination under this clause (ii) is not based on a valuation completed by an independent valuation firm within the 6 months preceding the Board’s determination, the Optionee may require the Company to retain an independent valuation firm to determine the fair market value (and the Company will bear the cost of such appraisal, unless the appraised value is 110% or less of the fair market value as determined by the Board, in which case the Optionee will bear the cost of such appraisal).
Section 1.7Fiscal Year
“Fiscal Year” shall mean each of calendar year 2008, 2009, 2010, 2011 and 2012.
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Section 1.8Good Reason
“Good Reason” shall mean “Good Reason” as defined in the employment agreement or change-in-control agreement between the Optionee and the Company or any of its Subsidiaries or Affiliates or, if there is no such employment or change-in-control agreement in effect at the time Optionee’s employment is terminated, “Good Reason” shall mean (i) a reduction in the Optionee’s base salary or the Optionee’s annual incentive compensation opportunity (other than a general reduction in base salary or annual incentive compensation opportunity that affects all salaried employees of the Company proportionately); (ii) a transfer of the Optionee’s primary workplace by more than thirty-five (35) miles from the current workplace; (iii) a substantial adverse change in the Optionee’s duties and responsibilities; (iv) any material breach by the Company of this Agreement, the Management Stockholder’s Agreement, or the Optionee’s employment agreement; or (v) an adverse change in the Optionee’s line of reporting to superior officers pursuant to the terms of his employment agreement or any change-in-control agreement;provided,however, that any isolated, insubstantial and inadvertent failure by the Company that is not in bad faith and is cured within ten (10) business days after the Optionee gives the Company written notice of any such event set forth above, shall not constitute Good Reason.
Section 1.9Grant Date
“Grant Date” means the date the Option, or a portion thereof, is granted, which is specified for each of the Original Time Option, the Performance Option, the Incremental Vesting Option and the Cliff Vesting Option in Section 2.1 hereof.
Section 1.10Incremental Vesting Option
“Incremental Vesting Option” shall have the meaning given such term in Section 2.1 hereof.
Section 1.11Job Elimination
“Job Elimination” shall mean the termination of an Optionee’s employment without Cause by the Company or any of its Subsidiaries or Affiliates in either of Fiscal Year 2011 or 2012 due to the elimination of the Optionee’s job position, to the extent determined by the Chief Executive Officer and approved by the Committee that such elimination occurred.
Section 1.12Liquidity Event
“Liquidity Event” shall mean the first to occur of any transaction or completion of a series of transactions that results, directly or indirectly, in the Sponsor Group or their Affiliates realizing with respect to their Shares, cash and/or publicly traded securities (includes Shares held by the Sponsor Group or their Affiliates, if then publicly traded and freely marketable securities) having a market value that at least equals the Sponsor Return or the Sponsor IRR, provided that if more than 25% of the aggregate amount realized is in the form of publicly traded securities, no portion of such excess may be taken into account in determining the Sponsor Return or Sponsor IRR until such securities are sold for cash in accordance with Section 3.1(d).
Section 1.13Management Stockholder’s Agreement
“Management Stockholder’s Agreement” shall mean the Management Stockholder’s Agreement between the Optionee and the Company.
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Section 1.14Marketable Securities
“Marketable Securities” shall mean (i) prior to a public offering, the equity securities of any acquiring entity that gains control of the Company or (ii) the registered Shares of the Company following a public offering.
Section 1.15Measurement Date
“Measurement Date” shall mean any date upon which a Liquidity Event occurs.
Section 1.16Option
“Option” shall mean the aggregate of the Original Time Option, the Performance Option, the Incremental Vesting Option and the Cliff Vesting Option.
Section 1.17Original Time Option
“Original Time Option” shall have the meaning given such term in Section 2.1 hereof.
Section 1.18Parent
“Parent” shall mean Texas Energy Future Holdings Limited Partnership, a Delaware Limited Partnership.
Section 1.19Performance Option
“Performance Option” shall have the meaning given such term in Section 2.1 hereof.
Section 1.20Retirement
“Retirement” shall mean the Optionee's retirement at age 55 or over after having been employed by the Company or a Subsidiary or Parent for at least ten (10) consecutive years (with at least five consecutive years of employment following the Closing Date).
Section 1.21Secretary
“Secretary” shall mean the Secretary of the Company.
Section 1.22Sponsor IRR
“Sponsor IRR” shall mean an amount equal to a pretax compounded annual internal rate of return of at least 20% on the aggregate amount paid by the Sponsor Group for all of their Shares. For the avoidance of doubt, (a) any calculation of Sponsor IRR will take into account cash dividends or other cash distributions paid on Shares, as well as the value of the Shares if and when they become publicly traded, and (b) any calculation of Sponsor IRR will not take into account the receipt by the Sponsor Group or any of their Affiliates of any management, monitoring, transaction or other fees payable to such parties by the Company or any of its Subsidiaries.
Section 1.23Sponsor Return
“Sponsor Return” shall mean, on any given date, an amount equal to the product of 3.0 (3.5 in respect of Fiscal Years 2016 and 2017) times the aggregate amount paid by the Sponsor Group for all of their Shares. For the avoidance of doubt, (a) any calculation of Sponsor Return will take into account cash dividends or other cash distributions paid on Shares, as well as the value of the Shares if and when they become publicly traded, and (b) any calculation of Sponsor Return will not take into account the receipt by the Sponsor Group or any of their Affiliates of any management, monitoring, transaction or other fees payable to such parties by the Company or any of its Subsidiaries. For purposes of this definition, the term “Fiscal Year” shall include calendar years 2016 and 2017.
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ARTICLE II
GRANT OF OPTIONS
Section 2.1Grant of Options
This Agreement evidences the grant to the Optionee, for good and valuable consideration and in each case on the terms and conditions set forth in this Agreement, of the following:
(a) an option to purchase Shares, previously granted to Optionee on 2008, which shall vest in accordance with the provisions of Section 3.1(a)(i) hereof (the “Original Time Option”);
(b) an option to purchase Shares, previously granted to the Optionee on , 2008, which shall vest in accordance with the provisions of Section 3.1(a)(ii) hereof (the “Performance Option”);
(c) an option to purchase Shares, granted to the Optionee on , 2009, which shall vest in accordance with the provisions of Section 3(a)(iii) hereof (the “Incremental Vesting Option”); and
(d) an option to purchase Shares, granted to the Optionee on 2009, which shall vest in accordance with the provisions of Section 3.1(a)(iv) hereof (the “Cliff Vesting Option”).
The Optionee acknowledges that his acceptance of this Agreement constitutes his agreement to the surrender and cancellation in full of all of his right, title and interest in the right to purchase Shares, which was previously awarded to Optionee as part of the Performance Option pursuant to the Original Option Agreement, with no further obligations of the Company thereunder.
Section 2.2Exercise Price
Subject to Section 2.4, the exercise price of the Shares covered by the Option shall be equal to (a) $ per Share for the Original Time Option and the Performance Option, and (b) $ per Share for the Incremental Vesting Option and the Cliff Vesting Option (each applicable price, the “Exercise Price”).
Section 2.3No Guarantee of Employment
Nothing in this Agreement or in the Plan shall confer upon the Optionee any right to continued employment by the Company or any Subsidiary or Affiliate or shall interfere with or restrict in any way the rights of the Company and its Subsidiaries or Affiliates, which are hereby expressly reserved, to terminate the employment of the Optionee at any time for any reason whatsoever, with or without Cause, subject to the applicable provisions of, if any, the Optionee’s employment agreement with the Company.
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Section 2.4Adjustments to Option
The Option shall be subject to the adjustment provisions of Sections 8 and 9 of the Plan,provided,however, that in the event of the payment of an extraordinary dividend by the Company to its stockholders, then: the Exercise Price of the Option shall be reduced by the amount of the dividend paid, but only to the extent the Committee determines it to be permitted under applicable tax laws and not to have adverse tax consequences to the Optionee under Section 409A of the Code; and, if such reduction cannot be fully effected due to such tax laws without adverse tax consequences to the Optionee, then the Company shall pay to the Optionee a cash payment, on a per Share basis, equal to the balance of the amount of the dividend not permitted to be applied to reduce the Exercise Price of the applicable Option as follows: (a) for each Share subject to a vested Option, immediately upon the date of such dividend payment; and (b), for each Share subject to an unvested Option, on the date on which such Option becomes vested and exercisable with respect to such Share.
ARTICLE III
PERIOD OF EXERCISABILITY
Section 3.1Commencement of Exercisability
(a) So long as the Optionee continues to be employed by the Company or any other Service Recipients, the Option shall become exercisable pursuant to the following schedules:
(i)Original Time Option. The Original Time Option shall become vested and exercisable in accordance with the following schedule, provided the Optionee has remained continuously employed by the Company or any other Service Recipients through the applicable vesting dates:
Vesting Date | Cumulative Percentage of Shares Subject to the Original Time Option that are Vested and Exercisable | |
September 30, 2008 | 20% | |
September 30, 2009 | 40% | |
September 30, 2010 | 60% | |
September 30, 2011 | 80% | |
September 30, 2012 | 100% | |
(ii)Performance Option. The Performance Option shall be eligible to become vested and exercisable as to 20% of the Shares subject to such Option at the end of each of the five Fiscal Years if the Company, on a consolidated basis, achieves its annual EBITDA targets as set forth inSchedule A attached hereto (each, an “EBITDA Target”) for the given Fiscal Year. Notwithstanding the foregoing, in the event that an EBITDA Target is not achieved in a particular Fiscal Year, then that portion of the Performance Option that was eligible to vest but failed to vest due to the Company’s failure to achieve its EBITDA Target shall nevertheless vest and become exercisable at the end of either of the two immediately subsequent Fiscal Yearsif the applicable two- or three-year cumulative EBITDA Target (each, a “Cumulative EBITDA Target”) set forth onSchedule A attached hereto is achieved on a cumulative basis at the end of either of the two immediately subsequent Fiscal Years with respect to a Fiscal Year completed no more than two years prior to the then completed Fiscal Year(s); provided that, in the event that an EBITDA Target is not achieved in either of Fiscal Years 2011 or 2012, then that portion of the Performance Option that was eligible to vest but failed to vest due to the Company’s failure to achieve its EBITDA Target or the applicable Cumulative EBITDA Target shall nevertheless vest and become exercisable at the end of either of the two immediately subsequent Fiscal Years of the Companyif the budgeted EBITDA target set by the Board and the Committee in respect of such Fiscal Year of the Company is achieved and the excess over such budgeted amount is sufficient to satisfy the shortfall from Fiscal Year 2011 or 2012. For purposes of the foregoing proviso clause, the term “Fiscal Year” shall include calendar years 2013 and 2014.
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(iii)Incremental Vesting Option. The Incremental Vesting Option shall become vested and exercisable with respect to 20% of the Shares subject to the Incremental Vesting Option on each of September 30, 2010, September 30, 2011, September 30, 2012, September 30, 2013, and September 30, 2014, provided the Optionee has remained continuously employed by the Company or any other Service Recipients through the applicable vesting dates.
(iv)Cliff Vesting Option. The Cliff Vesting Option shall become vested and exercisable with respect to 100% of the Shares subject to the Cliff Vesting Option on September 30, 2014, provided the Optionee has remained continuously employed by the Company or any other Service Recipients through September 30, 2014.
(b) Notwithstanding any of Section 3.1(a) above, upon the occurrence of a termination of employment without Cause, termination of employment on account of the Company or other applicable Service Recipient’s failure to renew the Optionee’s existing employment agreement, or a resignation by the Optionee for Good Reason, in each case following the occurrence of a Change in Control, the Original Time Option shall become immediately exercisable as to 100% of the Shares subject to such Option immediately prior to the Change of Control.
(c) Notwithstanding any of Section 3.1(a) above, upon the occurrence of a Change in Control, the Incremental Vesting Option and Cliff Vesting Option shall become immediately exercisable as to 100% of the Shares subject to each such Option immediately prior to the Change of Control, provided that the Optionee remains continuously employed by the Company or any other Service Recipients on the date such Change in Control occurs.
(d) Notwithstanding any of Section 3.1(a) above, upon the occurrence of a Liquidity Event, subject to the Optionee being employed on the date of such event, the Performance Option shall become immediately exercisable as to 100% of the Shares subject to such Option immediately prior to the Liquidity Event (but only to the extent such Option has not otherwise terminated or become exercisable). If Sponsor IRR and Sponsor Return would not be achieved as a result of the Performance Options becoming immediately exercisable as to 100% of the Shares subject to such Option pursuant to the preceding sentence, “100%” in the preceding sentence shall be replaced with the maximum percentage so that either the Sponsor IRR or Sponsor Return is achieved. In the event that the Sponsor Group receives Marketable Securities in an event constituting a Measurement Date (including, following a public offering, Shares) in excess of more than 25% of the aggregate amount realized in such event, (1) Sponsor IRR and Sponsor Return shall be initially calculated at the time of the Measurement Date without regard to the value of such Marketable Securities so received and such resulting Sponsor Return and Sponsor IRR shall be used to determine vesting of Shares subject to the Performance Option in accordance with this Section 3.1(d); and (2) if the Sponsor Return and/or Sponsor IRR as calculated in (1) above do not result in 100% vesting of the outstanding exercisable Shares subject to such Performance Option immediately prior to the Measurement Date, Sponsor Return and Sponsor IRR shall be recalculated upon each direct or indirect disposition of such Marketable Securities by the Sponsor Group for cash, discounting the cash received to determine its present value at the time of the Measurement Date. If such recalculated Sponsor IRR and/or Sponsor Return would have resulted in 100% vesting of all Shares subject to the Performance Option at the time of the Measurement Date, then 100% of such Performance Option shall immediately vest;provided,however, that any Optionee whose employment is terminated without Cause by the Company or as a result of the Company or other applicable Service Recipient’s failure to renew his employment agreement, or who terminates his employment for Good Reason, such Optionee’s Performance Option, or a portion thereof, having been forfeited or cancelled between the occurrence of the Measurement Date and the subsequent vesting of such Performance Option, in accordance with this Section 3.1(d), shall be entitled to the difference between the price per Share paid on the Measurement Date and the strike price of the Performance Option that was so cancelled or forfeited.
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(e) Except as provided above, no Option shall become exercisable as to any additional Shares following the termination of employment of the Optionee for any reason and any Option, which is unexercisable as of the Optionee’s termination of employment, shall immediately expire without payment therefor.
Section 3.2Expiration of Option
Except as otherwise provided in Section 5 or 6 of the Management Stockholder’s Agreement, the Optionee may not exercise the Option, or any portion thereof, to any extent after the first to occur of the following events:
(a) The tenth anniversary of the applicable Grant Date;
(b) The first anniversary of the date of the Optionee’s termination of employment with the Company and all Service Recipients, if the Optionee’s employment is terminated by reason of death or Disability;
(c) Immediately upon the date of an Optionee’s termination of employment by the Company and all Service Recipients for Cause;
(d) Thirty (30) days after the date of an Optionee’s resignation from employment with the Company and all Service Recipients without Good Reason (except due to death or Disability);
(e) One hundred and eighty (180) days after the date of: (i) an Optionee’s resignation from employment with the Company and all Service Recipients for Good Reason; (ii) an Optionee’s Retirement; or (iii) an Optionee’s termination of employment by the Company and all Service Recipients without Cause (for any reason other than death, Disability, or Job Elimination), including upon nonrenewal of Optionee’s existing employment agreement by the Company or other applicable Service Recipient, in the event such termination listed in (i), (ii), or (iii) occurs prior to the fifth anniversary of the Closing Date;
(f) The Extended Exercise Date in the event of (i) an Optionee’s resignation from employment with the Company and all Service Recipients for Good Reason; (ii) an Optionee’s Retirement; or (iii) an Optionee’s termination of employment by the Company and all Service Recipients without Cause (for any reason other death, Disability, or Job Elimination), including upon nonrenewal of Optionee’s existing employment agreement by the Company or other applicable Service Recipient, and any such termination listed in (i), (ii), or (iii) occurs on or after the fifth anniversary of the Closing Date;
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(g) The Extended Exercise Date in the event of an Optionee’s Job Elimination;
(h) Immediately upon the date of an Optionee’s breach of the provisions of Section 22(a)(ii) of the Management Stockholder’s Agreement; or
(i) At the discretion of the Company, if the Committee so determines pursuant to Section 9 of the Plan, but only to the extent the Committee determines it to be permitted under applicable tax laws and to not have adverse tax consequences to the Optionee under Section 409A of the Code.
Notwithstanding the foregoing, the time periods set forth in this Section 3.2 shall not begin to run with respect to Performance Options that vest in accordance with Section 3.1(a)(ii) above until the time at which the Board certifies the financial statements for the Company for the Fiscal Year immediately preceding the Fiscal Year in which, or for the Fiscal Year in which, termination of employment occurs. For purposes of the foregoing provision, the term “Fiscal Year” shall include calendar years 2013 and 2014.
ARTICLE IV
EXERCISE OF OPTION
Section 4.1Person Eligible to Exercise
During the lifetime of the Optionee, only the Optionee (or his duly authorized legal representative) may exercise the Option or any portion thereof. After the death of the Optionee, any exercisable portion of the Option may, prior to the time when an Option becomes unexercisable under Section 3.2, be exercised by his personal representative or by any person empowered to do so under the Optionee’s will or under the then applicable laws of descent and distribution.
Section 4.2Partial Exercise
Any exercisable portion of the Option or the entire Option, if then wholly exercisable, may be exercised in whole or in part at any time prior to the time when the Option or portion thereof becomes unexercisable under Section 3.2;provided,however, that any partial exercise shall be for whole Shares only.
Section 4.3Manner of Exercise
The Option, or any exercisable portion thereof, may be exercised solely by delivering to the Secretary or her office all of the following prior to the time when the Option or such portion becomes unexercisable under Section 3.2:
(a) Notice in writing signed by the Optionee or the other person then entitled to exercise the Option or portion thereof, stating that the Option or portion thereof is thereby exercised, such notice complying with all applicable rules established by the Committee;
(b) (i) Full payment (in cash, by check, or by a combination thereof or through tender of previously owned Shares (any such Shares valued at Fair Market Value on the date of exercise) that the Participant has held for at least six months (or such other period as may be required by the Company’s accountants but only to the extent required to avoid liability accounting under FAS 123(R) or any successor standard thereto)) for the Shares with respect to which such Option or portion thereof is exercised or (ii) indication that the Optionee elects to have the number of Shares that would otherwise be issued to the Optionee reduced by a number of Shares having an equivalent Fair Market Value to the payment that would otherwise be made by the Optionee to the Company pursuant to clause (i) of this subsection (b);
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(c) (i) Full payment (in cash or by check or by a combination thereof) to satisfy the minimum withholding tax obligation with respect to which such Option or portion thereof is exercised; or (ii) notice in writing that the Optionee elects to have the number of Shares that would otherwise be issued to the Optionee reduced by a number of Shares having an equivalent Fair Market Value to the payment that would otherwise be made by the Optionee to the Company pursuant to clause (i) of this subsection (c);
(d) A bona fide written representation and agreement, in a form satisfactory to the Committee, signed by the Optionee or other person then entitled to exercise such Option or portion thereof, stating that the Shares are being acquired for his own account, for investment and without any present intention of distributing or reselling said Shares or any of them except as may be permitted under the Securities Act of 1933, as amended (the “Act”), and then applicable rules and regulations thereunder, and that the Optionee or other person then entitled to exercise such Option or portion thereof will indemnify the Company against and hold it free and harmless from any loss, damage, expense or liability resulting to the Company if any sale or distribution of the Shares by such person is contrary to the representation and agreement referred to above;provided,however, that the Committee may, in its reasonable discretion, take whatever additional actions it deems reasonably necessary to ensure the observance and performance of such representation and agreement and to effect compliance with the Act and any other federal or state securities laws or regulations; and
(e) In the event the Option or portion thereof shall be exercised pursuant to Section 4.1 by any person or persons other than the Optionee, appropriate proof of the right of such person or persons to exercise the Option.
Without limiting the generality of the foregoing, the Committee may require an opinion of counsel acceptable to it to the effect that any subsequent transfer of Shares acquired on exercise of an Option does not violate the Act, and may issue stop-transfer orders covering such Shares. Share certificates evidencing stock issued on exercise of this Option shall bear an appropriate legend referring to the provisions of subsection (d) above and the agreements herein. The written representation and agreement referred to in subsection (d) above shall, however, not be required if the Shares to be issued pursuant to such exercise have been registered under the Act, and such registration is then effective in respect of such Shares.
Section 4.4Conditions to Issuance of Stock Certificates
The Shares deliverable upon the exercise of the Option, or any portion thereof, may be either previously authorized but unissued Shares or issued Shares, which have then been reacquired by the Company. Such Shares shall be fully paid and nonassessable. The Company shall not be required to issue or deliver any certificate or certificates for Shares of stock purchased (if certified, or if not certified, register the issuance of such Shares on its books and records) upon the exercise of the Option or a portion thereof prior to fulfillment of all of the following conditions:
(a) The obtaining of approval or other clearance from any state or federal governmental agency which the Committee shall, in its reasonable and good faith discretion, determine to be necessary or advisable;
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(b) The execution by the Optionee of the Management Stockholder’s Agreement and a Sale Participation Agreement; and
(c) The lapse of such reasonable period of time following the exercise of the Option as the Committee may from time to time establish for reasons of administrative convenience or as may otherwise be required by applicable law.
Section 4.5Rights as Stockholder
Except as otherwise provided in Section 2.4 of this Agreement, the holder of an Option shall not be, nor have any of the rights or privileges of, a stockholder of the Company with respect to any Shares purchasable upon the exercise of the Option or any portion thereof unless and until certificates representing such Shares shall have been issued by the Company to such holder or the Shares have otherwise been recorded in the records of the Company as owned by such holder.
ARTICLE V
MISCELLANEOUS
Section 5.1Administration
The Committee shall have the power to interpret the Plan and this Agreement and to adopt, interpret, or revoke rules for the administration, interpretation and application of the Plan. All actions taken and all interpretations and determinations made by the Committee shall be final and binding upon the Optionee, the Company and all other interested persons. No member of the Committee shall be personally liable for any action, determination or interpretation made in good faith with respect to the Plan or the Option. In its absolute discretion, the Board may at any time and from time to time exercise any and all rights and duties of the Committee under the Plan and this Agreement.
Section 5.2Option Not Transferable
Neither the Option nor any interest or right therein or part thereof shall be liable for the debts, contracts or engagements of the Optionee or his successors in interest or shall be subject to disposition by transfer, alienation, anticipation, pledge, encumbrance, assignment or any other means whether such disposition be voluntary or involuntary or by operation of law by judgment, levy, attachment, garnishment or any other legal or equitable proceedings (including bankruptcy), and any attempted disposition thereof shall be null and void and of no effect;provided,however, that this Section 5.2 shall not prevent transfers by will or by the applicable laws of descent and distribution.
Section 5.3Notices
Any notice to be given under the terms of this Agreement to the Company shall be addressed to the Company in care of its Secretary, and any notice to be given to the Optionee shall be addressed to him at the last address on file with the Company. By a notice given pursuant to this Section 5.3 either party may hereafter designate a different address for notices to be given to that party. Any notice, which is required to be given to the Optionee, shall, if the Optionee is then deceased, be given to the Optionee’s personal representative if such representative has previously informed the Company of his status and address by written notice under this Section 5.3. Any notice shall have been deemed duly given when (i) delivered in person or (ii) enclosed in a properly addressed, sealed envelope or wrapper deposited (with postage or fees prepaid) with a post office or branch post office regularly maintained by the United States Postal Service, or an office regularly maintained by FedEx, UPS, or comparable non-public mail carrier.
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Section 5.4Titles; Pronouns
Titles are provided herein for convenience only and are not to serve as a basis for interpretation or construction of this Agreement. The masculine pronoun shall include the feminine and neuter, and the singular the plural, where the context so indicates.
Section 5.5Applicability of Plan, Management Stockholder’s Agreement and Sale Participation Agreement
The Option and the Shares issued to the Optionee upon exercise of the Option shall be subject to all of the terms and provisions of the Plan, the Management Stockholder’s Agreement and a Sale Participation Agreement, to the extent applicable to the Option and such Shares.
Section 5.6Amendment
Subject to Section 10 of the Plan, this Agreement may be amended only by a writing executed by the parties hereto, which specifically states that it is amending this Agreement.
Section 5.7Governing Law
The laws of the State of Texas shall govern the interpretation, validity and performance of the terms of this Agreement regardless of the law that might be applied under principles of conflicts of laws.
Section 5.8Arbitration
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 within the Dallas, Texas metropolitan area. 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. Each party shall bear its own legal fees and expenses, unless otherwise determined by the arbitrator.
[Signatures on next page.]
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IN WITNESS WHEREOF, this Agreement has been executed and delivered by the parties hereto.
| ENERGY FUTURE HOLDINGS CORP. | ||
| By: |
| |
| Name: |
| |
| Title: |
| |
| OPTIONEE: | ||
| ||
| ADDRESS: | ||
| ||
|
Summary of Option grants governed by this Agreement appears on the following page.
[Signature Page of Stock Option Agreement]
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Summary of Option
| Original Time Option | Performance Option | Incremental Vesting Option | Cliff Vesting Option | |||||
Aggregate number of Shares subject to the Option | ||||||||
Grant Date | ||||||||
Exercise Price | ||||||||
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Exhibit 10(cc)
SEVERANCE AND RELEASE AGREEMENT
This Severance and Release Agreement (the “Agreement”) is entered into on October 5, 2009 by and between Energy Future Holdings Corp. (the “Company”), and M. Rizwan Chand (“Executive”). Executive and the Company are referred to in this Agreement as the “Parties.”
RECITALS
WHEREAS, Executive has been employed by and served as an officer of the Company, most recently as its Executive Vice President for Human Resources & Administration;
WHEREAS,the Company previously notified Executive that his employment would be terminated without Cause, as defined in the employment agreement between Executive and the Company dated May 23, 2008 (“Employment Agreement”);
WHEREAS, after such notice Executive agreed to remain fully engaged and to assist the Company with completion of key projects, identification of a successor and orderly transition of his job duties prior to his termination; and
WHEREAS, the Company and Executive desire to enter into this Agreement setting forth the terms of Executive’s remaining employment with and separation from the Company.
NOW, THEREFORE, in consideration of the promises and mutual agreements in this Agreement, and for other good and valuable consideration, the receipt and legal sufficiency which are acknowledged, the Company and Executive agree as follows:
ARTICLE 1
TERMINATION OF EMPLOYMENT
Effective 5:00 p.m. on October 5, 2009 (the “Separation Date”), Executive’s employment with the Company will end and he will resign from all positions he holds as an officer of the Company and any entity that controls, is controlled by, or is under common control with the Company (an “Affiliate”), including, but not limited to, those Affiliates listed on Exhibit 1 to this Agreement.
On or before the Separation Date, Executive will return all property of the Company and its Affiliates, including all Confidential Information (as defined below), in his possession. If Executive discovers, or comes into possession of, any such Confidential Information after the Separation Date, he shall promptly return it to the Company’s General Counsel.
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ARTICLE 2
SEVERANCE PAYMENT AND BENEFITS
2.1 Severance Payments
| a. | Consistent with Section 7.c. of the Employment Agreement, and in consideration for the promises contained in this Agreement including Executive’s commitment to remain engaged and assist the Company with transition of his duties through the Separation Date, the Company will provide Executive with the payments and benefits described below: |
| (i) | Accrued Rights. a) a lump sum payment within ten (10) business days following the Separation Date for Executive’s base salary and accrued and unused vacation, up to and as of the Separation Date, to the extent Executive has not otherwise been paid for them; b); any unpaid expense reimbursements or other cash entitlements accrued by or payable to Executive as of the Separation Date under the terms of any applicable plan or policy provided that such reimbursement requests are supported by appropriate documentation and submitted within ninety (90) days following the Separation Date; and c) such employee benefits or other amounts owed but unpaid to Executive under any plan, policy, program, or agreement between the Company and Executive and in accordance with the terms of such plan, policy, program, or agreement. |
| (ii) | Severance Payment. A one-time, lump-sum cash payment of one million, four hundred eighty five thousand dollars ($1,485,000). Such payment shall be made within ten (10) business days after the expiration of the Revocation Period. |
| (iii) | Healthcare Coverage under the Consolidated Omnibus Budget Reconciliation Act of 1985 (“COBRA”). Provided Executive does not violate the restrictions set forth in Section 5, below, Executive, his spouse, and his eligible dependents (to the extent covered immediately before the Separation Date) shall continue to be eligible to participate in all of the Company’s group health plans on the same terms and conditions as active employees of the Company until the earlier of (x) two (2) years from the Separation Date (the “Severance Period”), or (y) until Executive is, or becomes, eligible for comparable coverage under the group health plans of a subsequent employer. If Executive continues to receive benefits pursuant to this Section 2.1.a.(iii) when, in the absence of the benefits provided in this Section 2.1.a.(iii), Executive would not be entitled to continuation coverage under Section 4980B of the Internal Revenue Code of 1986, as amended (the“Code”), Company shall reimburse Executive for all medical expenses no later than the end of the calendar year immediately following the calendar year in which the applicable expenses were incurred. The COBRA health care continuation coverage period under Section 4980B of the Code, or any replacement or successor provision of United States tax law, shall run concurrently with the Severance Period. |
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| (iv) | Assistance with Preparation of 2009 Income Tax Return. The Company shall pay up to two thousand dollars ($2000.00) to the Ayco Company, LP (“AYCO”) to assist Executive with preparation of his 2009 tax return; provided that AYCO shall provide all such assistance during the 2010 calendar year. |
2.2 Other Benefits
| a. | It is agreed that, from and after the Separation Date, Executive shall not be eligible to continue to participate in any employee benefit plan, program, or policy sponsored by the Company or any Affiliate, except for rights that have vested as of the Separation Date or as specifically provided in this Agreement. |
| b. | Executive will be entitled to receive a distribution of (or, in the case of stock options, entitled to exercise) his vested awards or vested account balances under, and subject to the provisions of, each of the governing plan documents of the following employee benefit plans and other terms described in the Employment Agreement: |
| (i) | EFH Retirement Plan (Cash Balance formula); |
| (ii) | EFH Thrift Plan; |
| (iii) | EFH Salary Deferral Plan (“SDP”); |
| (iv) | EFH Health Care and Life Insurance Plan; and |
| (v) | 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates. |
| c. | Deferred Shares.In lieu of any rights Executive may have under the Deferred Share Agreement dated May 27, 2008 between Executive and the Company, the Company will pay to Executive the amount of six hundred thousand dollars ($600,000) to satisfy the Company’s retention payment obligation. Such payment shall be made within ten (10) business days after the expiration of the Revocation Period. |
| d. | Unvested and Otherwise Forfeited SDP Contributions. Executive shall be entitled to receive a distribution of contributions made by the Company to Executive’s SDP account that would otherwise be forfeited under the SDP, at the same time that such contributions would otherwise be paid under the SDP absent forfeiture. |
2.3Exclusivity of Benefits and Withholdings. The Company and Executive agree that the payments and benefits described in this Article 2 shall be the only benefits Executive receives following separation and are in lieu of any other separation or severance benefits offered under any plan, program, or agreement (including the Employment Agreement) to which Executive may have been, or to which Executive believes he may be, entitled as a result of his employment with or separation from the Company or any Affiliate. Any such payments shall be less any applicable taxes and withholdings, deductions, or obligations, including, to the extent permitted by Section 409A of the Code, any amounts owed to the Company or an Affiliate by Executive on any Company issued or sponsored travel or credit cards or any other expenses or payments for which the Company is entitled to be reimbursed by Executive.
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ARTICLE 3
WAIVER AND RELEASE
3.1 Release of Company by Executive
Executive represents that he has not filed any complaints of any kind whatsoever with any local, state, federal, or governmental agency or court against the Company based upon, or in any way related to, Executive’s employment with the Company. Executive further represents that he understands that the payments and benefits provided for in Article 2 constitute a full and complete satisfaction of any claims, asserted or unasserted, known or unknown, that Executive has or may have against the Company or an Affiliate except as provided below. In exchange for the payments to be made by the Company and benefits to be received by Executive under this Agreement, Executive, individually and on behalf of Executive’s spouse, heirs, successors, and assigns, hereby agrees not to sue or instigate any grievance, charge, claim, action, or suit, at law or in equity, and unconditionally releases, dismisses, and forever discharges the Company, including its predecessors, successors, parents, subsidiaries, affiliated corporations, limited liability companies and partnerships, including (but not limited to) Energy Future Competitive Holdings Company, Energy Future Intermediate Holding Company LLC, Luminant Holding Company LLC, Luminant Energy Services Company, Luminant Mining Services Company, Luminant Power Services Company, EFH Corporate Services Company, TXU Retail Services Company, Texas Competitive Electric Holdings Company LLC, TXU Energy Retail Company LLC, Luminant Energy Company LLC, TXU Energy Solutions Company LLC, Oncor Electric Delivery Holdings Company LLC, Oncor Electric Delivery Company LLC, Luminant Generation Company LLC, Generation MT Company LLC, Generation SVC Company, Luminant Mining Company LLC, Big Brown Power Company LLC, Collin Power Company LLC, DeCordova Power Company LLC, Oak Grove Power Company LLC, Oak Grove Management Company LLC, Sandow Power Company LLC, Tradinghouse Power Company LLC, Valley NG Power Company LLC, Comanche Peak Nuclear Power Company LLC, and all of their employee benefit plans, officers, directors, fiduciaries, employees, assigns, representatives, agents, and counsel (collectively the “Released Parties”) from any and all claims, demands, liabilities, obligations, agreements, damages, debts, and causes of action arising out of, or in any way connected with, Executive’s employment with or separation from the Company or any of the Released Parties through the date hereof. This waiver and release includes, but is not limited to, all claims and causes of action arising under or related to Title VII of the Civil Rights Act of 1964, as amended; the Civil Rights Act of 1991; the Civil Rights Act of 1866; Section 1981 of Title 42 of the United States Code, as amended; the Age Discrimination in Employment Act of 1967, as amended; the Americans with Disabilities Act; the Employee Retirement Income Security Act of 1974, as amended; Section 211 of the Energy Reorganization Act; the Sarbanes-Oxley Act of 2002; the Older Workers Benefit Protection Act of 1990; the Worker Adjustment and Retraining Notification Act; the Occupational Safety and Health Act, as amended; the Family and Medical Leave Act; the Texas Labor Code, including (but not limited to) Chapter 451; the Texas Commission on Human Rights Act; all state and federal statutes and regulations; all oral or written contract rights, including any rights under any Company incentive plan, program, or labor agreement; and all claims arising under common law including breach of contract, tort, or for personal injury of any sort.
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Executive understands that this Waiver and Release precludes him from recovering any relief as a result of any lawsuit, grievance, or claim brought on his behalf and arising out of his employment or separation from employment with the Company. However, nothing in this Waiver and Release restricts Executive in any way from truthful communications with, filing a charge or complaint with, or full cooperation in the investigation(s) of, any governmental agency on matters within their jurisdictions or from cooperating with the Company in any internal investigation. Furthermore, nothing in this Waiver and Release shall preclude any claim relating to: (i) Executive’s rights under this Agreement (ii) Executive’s rights under the Employment Agreement with respect to the imposition of excise taxes imposed pursuant to Section 4999 of the Code (“Excise Taxes”) arising by reason of or in connection with the October 10, 2007 closing of the transactions contemplated by the agreement and plan of merger among TXU Corp., Texas Energy Future Holdings Limited Partnership and Texas Energy Future Merger Sub Corp (the “Merger Agreement”), (iii) any rights to indemnification (including any rights to advancement or payment of defense and/or related legal costs) and rights to coverage under director and officer liability insurance under Section 9(h) of the Employment Agreement or Section 6.11 of the Merger Agreement, and (iv) facts, agreements, or causes of action arising after the date hereof.
3.2 Release of Executive by Company.The Company, on behalf of itself and its Affiliates, hereby releases, discharges and agrees to indemnify and hold harmless Executive from any and all claims and causes of action that it or they may have against Executive arising out of his employment with or separation from the Company or any Affiliate. This agreement to release, discharge, and indemnify does not include claims for violation of any law, including any securities law or willful misconduct. The Company acknowledges that it is not aware of any such conduct as of the execution of this Agreement. The Company further acknowledges and agrees that Executive’s sole obligations to Company from and after the Separation Date are set forth in this Agreement and that, except as provided below, all prior and contemporaneous agreements, whether written or oral, are terminated and of no further force and effect as of the Separation Date.
ARTICLE 4
CONSULTATION AND REVOCATION PERIODS
Executive understands that signing this Agreement, including the Waiver and Release described in Article 3, is an important legal act. Executive acknowledges that he has been advised to consult with legal counsel of his own choosing in connection with the matters addressed in this Agreement. Executive further acknowledges that he had twenty-one (21) days from the day he received this offer to consider this Agreement. Executive understands further that, for a period of seven (7) days following his signing of this Agreement (“Revocation Period”), he may revoke his acceptance of the offer represented by this Agreement by delivering or mailing a written statement revoking his acceptance to the General Counsel, Energy Future Holdings Corp. at 1601 Bryan Street, 41st Floor, Dallas, Texas 75201. In the event of such a revocation, the terms of this Agreement will be null and void, and any payments made to Executive pursuant to this Agreement prior to such revocation (other than the Accrued Rights described under Section 2.1(a)(i) and any other payments the Company was otherwise legally obligated to make to Executive) must be promptly repaid to the Company. Executive expressly acknowledges a personal debt to the Company for the full amount of any such payments, plus any interest earned between the time of payment to Executive and his repayment to the Company, and agrees to promptly pay the Company the full amount of that debt.
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ARTICLE 5
NON-DISCLOSURE, NON-COMPETITION, NON-SOLICITATION
AND NON-DISPARAGEMENT
5.1 Confidentiality and Non-Disclosure
“Confidential Information” means information: (i) disclosed to or known by Executive as a consequence of or through his employment with the Company or an Affiliate; (ii) not publicly available or not generally known outside the Company or its Affiliates; and (iii) that relates to the business and development of the Company or its Affiliates. Any information that does not meet each of the criteria listed above in subsections (i) - (iii) shall not constitute Confidential Information. Without in any way limiting the foregoing and by way of example, Confidential Information shall include: all non-public information or trade secrets of the Company and its Affiliates that gives the Company or its Affiliates a competitive business advantage, the opportunity of obtaining such advantage, or disclosure of which might be detrimental to the interests of the Company or its Affiliates; information regarding the Company’s or an Affiliate’s business operations, such as financial and sales data (including budgets, forecasts, and historical financial data), information regarding tax matters, operational information, plans, and strategies; business and marketing strategies and plans for various products and services; rate and regulatory strategy and plans; information regarding suppliers, consultants, employees, and contractors; technical information concerning products, equipment, services, and processes; procurement procedures; pricing and pricing techniques; information concerning past, current and prospective customers, investors, and business affiliates; plans or strategies for expansion or acquisitions; budgets; research; trading methodologies and terms; communications information; evaluations, opinions, and interpretations of information and data; marketing and merchandising techniques; electronic databases; models; specifications; computer programs; contracts; bids or proposals; technologies and methods; training methods and processes; organizational structure; compensation and benefit information; personal data about Company employees and applicants; internal investigations, administrative actions and/or litigation; cost and pricing data; potential industry partners and contacts with such partners, payments or rates paid to consultants or other service providers; information provided to Company and/or its Affiliates by a third party under restrictions against disclosure or use by Company, its Affiliates or others; and Company files, physical or electronic documents, equipment, and proprietary data or material in whatever form including all copies of all such materials. Confidential Information also includes matters that Executive conceived or developed during his employment with the Company, as well as matters Executive learned from other employees or contractors of the Company.
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Executive understands and confirms that, as a result of his employment with the Company and its Affiliates, he has obtained Confidential Information. Executive hereby reconfirms his prior commitments in Section 8 of the Employment Agreement and Section II of the Code of Conduct, and hereby agrees to maintain all Confidential Information in strictest confidence. Accordingly, Executive will not: (a) use Confidential Information in any way (including, without limitation, to the detriment of the Released Parties or in any future business relationship of Executive); (b) publish or disclose any Confidential Information; or (c) authorize anyone else to use, publish, or disclose any Confidential Information. Executive also agrees and acknowledges that all terms and conditions contained in this Agreement, as well as negotiations related to the Agreement, are to remain strictly confidential and constitute Confidential Information. This Paragraph shall not prohibit Executive from: (i) discussing the Agreement with his tax or financial advisor; (ii) discussing the Agreement with his attorney or spouse upon their agreement to keep the Agreement and its terms confidential; (iii) advising a governmental taxing authority of the Severance Payment and Benefits or the existence of this Agreement in response to a question posed by such taxing authority; or (iv) providing Confidential Information in response to a valid court order or subpoena issued by a court or governmental agency, provided that Executive gives the Company reasonable notice of such and an opportunity to challenge the disclosure of such Confidential Information before such court or governmental agency. Executive agrees to provide the Company with reasonable notice of any attempts to compel disclosure of Confidential Information by promptly sending written notice to: the General Counsel, Energy Future Holdings Corp., 1601 Bryan Street, 41st Floor, Dallas, Texas, 75201.
5.2 Non-Disparagement
The Parties shall not make, repeat, or publish to any third party any false, disparaging, unflattering, accusatory, or derogatory remarks or references about or concerning the other Party, whether oral or in writing, or otherwise take or assist in any action that might reasonably be expected to cause damage or harm to the other Party, provided however that this Section 5.2 shall not apply to statements made by or about any affiliates (other than the Company and its subsidiaries) of Kohlberg Kravis Roberts & Co. LP, TPG Capital LP, Goldman Sachs & Co. or any future owner of the Company. Executive’s obligations under this Section 5.2 extend to remarks about or concerning the Released Parties and/or actions that might reasonably be expected to cause damage or harm to the Released Parties. The Company’s obligations under this Section 5.2 are limited to only those individuals who are Executive Officers of the Company (as defined in Rule 16a 1(f) of the Securities Exchange Act of 1934, as amended) at the time of the Separation Date and who are acting in their capacity as Executive Officers of the Company at the time they make a remark or reference that allegedly violates this Section 5.2. This Section 5.2 does not prohibit either Party from making truthful statements regarding the other Party or Released Parties while cooperating with a governmental investigation or testifying under oath. Executive acknowledges that he is making, after the opportunity to confer with counsel, a knowing, voluntary, and intelligent waiver of rights Executive may have to make disparaging comments regarding the Company, including rights under the First Amendment to the United States Constitution and any other applicable federal and state constitutional rights.
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5.3 Non-Competition
Executive hereby reconfirms his agreement in Section 8.a.(ii) of the Employment Agreement that he shall not, for a period of eighteen (18) months after the Separation Date, directly or indirectly, act as a proprietor, investor, director, officer, employee, substantial stockholder, consultant, or partner in any Competing Business in Texas or any other geographic area in which Texas Energy Future Holdings Limited Partnership, the Company or any of their respective subsidiaries operates or conducts business. For purposes of this Agreement, Competing Business shall mean any business that directly or indirectly competes, at the relevant determination date, with one or more of the businesses of the Company or any Affiliate in any geographic area where Texas Energy Future Holdings Limited Partnership, the Company, or any of their respective subsidiaries operates.
Notwithstanding the foregoing, the restrictions set forth in this Section 5.3 shall not apply with respect to Kohlberg Kravis Roberts & Co. L.P., TPG Capital L.P., and Goldman, Sachs & Co. or any of their affiliates that are not engaged in any business that competes, directly or indirectly, with the Company or any of its subsidiaries in any geographic area in which they operate. Moreover, for purposes of Article 5, Executive may, directly or indirectly own, solely as an investment, securities of any Person (as such term is used for purposes of Section 13(a) or 14(d) of the Securities and Exchange Act of 1934, as amended) engaged in the business of the Company or any Affiliate which is publicly traded on a national or regional stock exchange or quotation system or on the over the counter market if Executive (I) is not a controlling person of, or a member of a group which controls, such person and (II) does not, directly or indirectly, own 5% or more of any class of securities of such Person.
5.4 Non-Solicitation
Executive hereby reconfirms his agreement in Section 8.a.(iii) of the Employment Agreement that he shall not, for a period of eighteen (18) months following the Separation Date, directly or indirectly (A) solicit customers or clients of the Company or any Affiliate to terminate their relationship with the Company or an Affiliate or otherwise solicit such customers or clients to compete with any business of the Company or an Affiliate, or (B) solicit or offer employment to any person who is, or has been employed by the Company or any Affiliate at any time during the twelve (12) months immediately preceding the Separation Date. Notwithstanding the foregoing, the restrictions set forth in this Section 5.4 shall not apply with respect to Kohlberg Kravis Roberts & Co. L.P., TPG Capital L.P., and Goldman, Sachs & Co. or any of their affiliates that are not engaged in any business that competes, directly or indirectly, with the Company or any of its subsidiaries in any geographic area in which they operate.
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5.5 Reformation and Injunctive Relief
Notwithstanding Sections 5.1 through 5.4, above, if at any time a court holds that the restrictions stated in those sections are unreasonable or otherwise unenforceable under circumstances then existing, the Parties agree that the maximum period, scope or geographic area determined to be reasonable under such circumstances by such court will be substituted for the stated period, scope or area.
Because Executive’s services are unique and because Executive has had access to Confidential Information, the Parties agree that a breach of this Article 5 would cause immediate and irreparable loss, damage, and injury to the Company; that money damages for such a breach would be exceedingly difficult, if not impossible, to estimate, and that the Company would have no adequate remedy at law. In the event of a breach or threatened breach of this Agreement, the Company or any of its Affiliates, successors or assigns may, in addition to other rights and remedies existing in their favor, apply to any court of competent jurisdiction for specific performance and/or injunctive relief in order to enforce, or prevent any violations of the provisions hereof (without the posting of a bond or other security). Accordingly, Executive acknowledges and agrees that injunctive relief would be appropriate relief for such breach and to prevent further breaches. Notwithstanding the foregoing, in the event Executive breaches the covenants set forth in Article 5, the Company’s rights and remedies with respect to Executive’s Options, Option Stock, and Stock and payments related thereto, as those terms are defined in the Management Stockholder’s Agreement between Executive and the Company (the “MSA”), shall be limited to those set forth in Section 22(c) of the MSA.
ARTICLE 6
MISCELLANEOUS
6.1 Tax and Withholdings
| a. | Tax and Financial Implications of Agreement. Executive represents and agrees that he is not relying on the judgment or advice of the Company, any of the Released Parties, or their counsel, either directly or indirectly, with regard to the taxability of any amount paid pursuant to the terms of the Agreement. Executive further acknowledges and agrees that it is his responsibility to determine the tax consequences of such amounts. In the event that any of the Released Parties is required under law to pay taxes (income, social security, or other) or related interest or penalties on any part of the payments described in Article 2 as a result of Executive’s failure to do so or as a result of Executive’s treatment of those severance payments as non-taxable, Executive shall immediately reimburse the Released Parties the full amount of such tax or related payments. Otherwise, Executive shall be responsible for reasonable expenses, including legal fees, incurred by any of the Released Parties in obtaining compliance with or enforcement of the terms of this Paragraph, as well as for the full amount of reimbursement payments. With the exception of the first sentence in this Section 6.1a., this Section does not apply to the treatment of any Excise Taxes and any gross ups related thereto covered by Employment Agreement, which shall govern the parties’ obligations with respect to any such payments, expenses or penalties. |
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| b. | Withholding. The Company may withhold from any amounts payable under this Agreement such federal, state or local taxes as shall be required to be withheld pursuant to any applicable law or regulation. In addition, Executive expressly authorizes and agrees that any amounts that he owes the Company or any Released Parties may be offset and deducted from the payments to be made hereunder, including amounts owed under the energy conservation or appliance purchase programs, amounts owed for Company issued or sponsored travel or credit cards, vacation overpayment, and salary, bonus and benefit overpayments (the Company acknowledges that it is not aware of any such amounts as of the execution of this Agreement), provided that no offsets shall be applied to amounts that constitute deferred compensation under Section 409A of the Code. |
| c. | Section 409A. This Agreement is intended to comply with the requirements of Section 409A of the Code and shall in all respects be administered in accordance with Section 409A. All reimbursements and in-kind benefits provided under this Agreement shall be made or provided in accordance with the requirements of Section 409A of the Code, including, where applicable, the requirement that (i) any reimbursement shall be for expenses incurred during Executive’s lifetime (or during a shorter period of time specified in this Agreement or the Employment Agreement, as applicable), (ii) the amount of expenses eligible for reimbursement, or in-kind benefits provided, during a calendar year may not affect the expenses eligible for reimbursement, or in-kind benefits to be provided, in any other calendar year, (iii) the reimbursement of an eligible expense will be made on or before the last day of the calendar year following the year in which the expense is incurred, and (iv) the right to reimbursement or in-kind benefits is not subject to liquidation or exchange for another benefit. |
6.2 Severability; Judicial Modification
If any term, provision, covenant, or restriction of this Agreement is held by a court of competent jurisdiction to be invalid, void, or unenforceable, the remainder of this Agreement and the other terms, provisions, covenants, and restrictions hereof shall remain in full force and effect; they shall in no way be affected, impaired, or invalidated. It is hereby stipulated and declared to be the intention of the Parties that they would have executed this Agreement had the terms, provisions, covenants, and restrictions that may be hereafter declared invalid, void, or unenforceable not been initially included.
6.3 Survival of Covenants
The Parties agree that the covenants and agreements set forth in Articles 3, 5, and 6 of this Agreement are of a continuing nature, and they shall survive the expiration, termination, or cancellation of this Agreement, unless such Articles are specifically extinguished, terminated, or cancelled in a writing signed by both Parties and identified as an amendment to this Agreement.
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6.4 Assignment
This Agreement is personal between the Company and Executive. Executive may not sell, assign, or transfer any rights or interests created under this Agreement, or delegate any of his duties, without the prior written consent of the Company. The Company may, without Executive’s consent, assign this Agreement and its rights, benefits, and obligations hereunder to any of its Affiliates or a successor entity. In the event of an assignment by the Company to an Affiliate, the Company will act as a guarantor of any obligations to Executive arising from this Agreement.
6.5 Further Assurances
The Parties agree to perform any further acts and to execute and deliver any further documents which may be necessary or appropriate to carry out the purposes of this Agreement.
6.6 Cooperation
Executive hereby reconfirms his agreement in Section 9.n. of the Employment Agreement that, for a period of six (6) years after the Separation Date, Executive shall provide Executive’s reasonable cooperation in connection with any action or proceeding (or any appeal from any action or proceeding) which relates to events occurring during Executive’s employment hereunder, provided that the Company shall use reasonable efforts to avoid material interference with Executive’s business or personal activities. The Company shall pay all of Executive’s reasonable expenses incurred in connection with providing such cooperation.
6.7 Governing Law; Attorneys’ Fees and Costs
This Agreement shall be governed by, and construed and enforced in accordance with, the laws of the State of Texas, regardless of choice-of-law principles. Each party submits to the jurisdiction of the courts in Dallas County, Texas, and the Parties agree that the proper venue and jurisdiction for any cause of action relating to this Agreement (whether sounding in tort or contract) shall be in Dallas County, Texas. In the event any issue arising out of this Agreement is litigated by the Parties, the prevailing party shall be entitled to recover from the other party its reasonable attorneys’ fees and costs.
6.8 Notices
All notices from one party to the other shall be deemed to have been duly delivered when hand delivered or sent by United States certified mail, return receipt requested, postage prepaid, as follows:
| If to Executive: | If to the Company: | |
| M. Rizwan Chand | General Counsel | |
| at the address on file with the Company | Energy Future Holdings Corp. | |
1601 Bryan Street, 41st Floor Dallas, Texas 75201. | ||
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6.9 Non-Waiver
The failure of either Party to enforce or require timely compliance with any term or provision of this Agreement shall not be deemed to be a waiver or relinquishment of rights or obligations arising hereunder, nor shall any such failure preclude the enforcement of any term or provision or avoid the liability for any breach of this Agreement.
6.10 Merger/Entirety of Agreement
This Agreement constitutes the entire agreement between the Parties with respect to the subject matter of this Agreement. Except where specifically referenced otherwise in this Agreement, it supersedes and replaces any and all prior or contemporaneous negotiations, undertakings, understandings, or agreements (whether written or oral) of any kind between Executive and the Company with respect to the terms of Executive’s separation from the Company and its Affiliates except for Executive’s Management Stockholder’s Agreement, Sale Participation Agreement, and Key Employee Non-Qualified Stock Option Agreement.
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I HAVE READ THIS AGREEMENT AND FULLY UNDERSTAND ALL ITS TERMS AND WHAT THEY MEAN. NO OTHER PROMISE, INDUCEMENT, THREAT, AGREEMENT, OR UNDERSTANDING OF ANY KIND OR DESCRIPTION WHATSOEVER HAS BEEN MADE WITH OR TO ME TO CAUSE ME TO SIGN THIS AGREEMENT. I ENTER INTO AND SIGN THIS AGREEMENT KNOWINGLY AND VOLUNTARILY, WITHOUT DURESS OR COERCION OF ANY KIND WHATSOEVER, AND WITH THE INTENT OF BEING LEGALLY BOUND BY THIS AGREEMENT.
IN WITNESS WHEREOF, the Parties execute this Agreement as follows:
| EXECUTIVE | ||
/s/ M. Rizwan Chand | ||
| M. Rizwan Chand | ||
| THE COMPANY | ||
| By: | /s/ John F. Young | |
| John F. Young, Chief Executive Officer | ||
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Exhibit 1
| Big Brown Lignite Company LLC | Executive Vice President | |
| Big Brown Power Company LLC | Executive Vice President | |
| Collin Power Company LLC | Executive Vice President | |
| DeCordova Power Company LLC | Executive Vice President | |
| EFH CG Management Company LLC | Executive Vice President | |
| EFH Corporate Services Company | Executive Vice President | |
| Energy Future Competitive Holdings Company | Senior Vice President | |
| Energy Future Holdings Corp. | Executive Vice President | |
| Energy Future Intermediate Holding Company LLC | Executive Vice President | |
| Generation MT Company LLC | Executive Vice President | |
| Generation SVC Company | Executive Vice President | |
| Lone Star Energy Services, Inc. | Senior Vice President | |
| Luminant Big Brown Mining Company LLC | Executive Vice President | |
| Luminant Energy Company LLC | Executive Vice President | |
| Luminant Energy Services Company | Executive Vice President | |
| Luminant Energy Trading California Company | Executive Vice President | |
| Luminant Energy Trading Canada Limited | Executive Vice President | |
| Luminant ET Services Company | Executive Vice President | |
| Luminant Generation Company LLC | Executive Vice President | |
| Luminant Holding Company LLC | Executive Vice President | |
| Luminant Mineral Development Company LLC | Executive Vice President | |
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| Luminant Mining Company LLC | Executive Vice President | |
| Luminant Mining Services Company | Executive Vice President | |
| Luminant Power Services Company | Executive Vice President | |
| Luminant Renewables Company LLC | Executive Vice President | |
| Nuclear Energy Future Holdings II LLC | Executive Vice President | |
| Nuclear Energy Future Holdings LLC | Executive Vice President | |
| Texas Competitive Electric Holdings Company LLC | Senior Vice President | |
| Tradinghouse Power Company LLC | Executive Vice President | |
| TXU Chilled Water Solutions Company | Executive Vice President | |
| TXU Energy Retail Company LLC | Senior Vice President | |
| TXU Energy Retail Management Company LLC | Senior Vice President | |
| TXU Energy Solutions Company LLC | Executive Vice President | |
| TXU Retail Services Company | Executive Vice President | |
| TXU SEM Company | Executive Vice President | |
| TXU SESCO Company LLC | Executive Vice President | |
| TXU SESCO Energy Services Company | Executive Vice President | |
| Valley NG Power Company LLC | Executive Vice President | |
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Exhibit 10(dd)
EFH
SALARY DEFERRAL PROGRAM
As amended, effective January 1, 2010
Table of Contents
Contents
EFH Salary Deferral Program | ||
Section 1. Purpose | 1 | |
Section 2. Definitions | 1 | |
Section 3. Deferral Eligibility and Participation | 7 | |
Section 4. Election to Defer | 8 | |
Section 5. Matching Awards, Vesting and Forfeitures | 8 | |
Section 6. Investments and Earnings | 9 | |
Section 7. Participant Accounts | 12 | |
Section 8. Distribution of Accounts | 12 | |
Section 9. Certain Elections for Pre-April 1, 1998 Participants | 16 | |
Section 10. Nontransferability | 16 | |
Section 11. Designation of Beneficiaries | 17 | |
Section 12. Rights of Participants | 17 | |
Section 13. Administration | 17 | |
Section 14. Amendment or Termination of the Plan | 18 | |
Section 15. Corporate Changes | 18 | |
Section 16. Requirements of Law | 20 | |
Section 17. Withholding Taxes | 20 | |
Section 18. Investment and Funding | 20 |
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EFH SALARY DEFERRAL PROGRAM
(Amended effective January 1, 2010)
Section 1.Purpose
1.1Purpose. The EFH Salary Deferral Program (the “Plan”) was established, effective April 1, 1991. The Plan is being amended and restated, effective as of January 1, 2010, to reflect that, as of such date, the Plan is being split into two separate plans, in connection with which Oncor Electric Delivery Company LLC (“Oncor”) will establish the Oncor Salary Deferral Program (“Oncor Plan”), which shall be a spin-off from this Plan, and which represents all liabilities and proportional assets of the Plan relating to employees of Oncor, and all other Participants will continue to be covered under this Plan. This amendment and restatement furthermore reflects that benefits under this Plan are being offset by certain additional benefits to be provided under the EFH Retirement Plan.
The primary purpose of the Plan is to provide a mechanism for certain key employees of Participating Employers to defer a portion of their Salary and Bonus, to motivate key employees, and to recognize the contributions of such employees to the Company as the Plan sponsor. The Plan is designed as an unfunded arrangement maintained primarily for the purpose of providing deferred compensation for a select group of management or highly compensated employees as determined under the provisions of Section 201(2) of the Employee Retirement Income Security Act of 1974.
Section 2.Definitions
2.1Definitions. Whenever used herein, the following terms shall have the meanings set forth below:
(a) “Account” means the individual account maintained by the Company for each Participant for recording deferrals of Salary, Bonus and DICP Amounts made by each Participant in the Plan, Matching Awards made on behalf of each Participant in the Plan, and earnings on such Deferrals and Matching Awards.
(b) “Adjustment Date” means the last day of each calendar quarter and such other dates as the Committee in its discretion may prescribe.
(c) “Beneficiary” means the person or persons named by the Participant as the recipient(s) of any distribution remaining to be paid to the Participant under the Plan upon the Participant’s death.
(d) “Board of Directors” means the Board of Directors of the Company.
(e) “Bonus” means the cash portion of any annual incentive award paid by a Participating Employer to a Participant with respect to services to be performed by a Participant during a Plan Year under an annual incentive plan adopted by such Participating Employer.
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(f) “Business Unit” means a subsidiary, division or operating unit of the Company designated by the Chief Executive of the Company which will focus on its own unique products, services and markets.
(g) “Change in Control” means the occurrence of any one or more of the following events:
(i) individuals who, on May 20, 2005, constitute the Board of Directors (the “Board”) of the Company (the “Incumbent Directors”) cease for any reason to constitute at least a majority of the Board, provided that any person becoming a director subsequent to May 20, 2005 whose election or nomination for election was approved by a vote of at least two-thirds of the Incumbent Directors then on the Board (either by a specific vote or by approval of the proxy statement of the Company in which such person is named as a nominee for director, without written objection to such nomination) shall be an Incumbent Director; provided, however, that no individual initially elected or nominated as a director of the Company as a result of an actual or threatened election contest with respect to directors or as a result of any other actual or threatened solicitation of proxies or consents by or on behalf of any person other than the Board shall be deemed to be an Incumbent Director;
(ii) any “person” (as such term is defined in Section 3(a)(9) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and as used in Sections 13(d)(3) and 14(d)(2) of the Exchange Act) is or becomes a “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Company representing 25% or more of the combined voting power of the Company’s then outstanding securities eligible to vote for the election of the Board (the “Company Voting Securities”); provided, however, that the event described in this paragraph (ii) shall not be deemed to be a Change in Control by virtue of any of the following acquisitions: (A) by the Company or any entity a majority of the voting securities or other voting interests of which are owned, directly or indirectly, by the Company (“Subsidiary”), (B) by any employee benefit plan (or related trust) sponsored or maintained by the Company or any Subsidiary, (C) by any underwriter temporarily holding securities pursuant to an offering of such securities, (D) pursuant to a Non-Qualifying Transaction (as defined in paragraph (iii) below), (E) with respect to any Eligible Executive, pursuant to any acquisition by such Eligible Executive or any group of persons including such Eligible Executive (or any entity controlled by such Eligible Executive or controlled by any group of persons including such Eligible Executive); or (F) a transaction (other than one described in paragraph (iii) below) in which Company Voting Securities are acquired from the Company, if a majority of the Incumbent Directors approve a resolution providing expressly that the acquisition pursuant to this clause (F) does not constitute a Change in Control under this paragraph (ii);
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(iii) the consummation of a merger, consolidation, statutory share exchange or similar form of corporate transaction involving the Company or any of its Subsidiaries that requires the approval of the Company’s shareholders other than approval required solely by Article XI of the Company’s articles of incorporation, whether for such transaction or the issuance of securities in the transaction (a “Business Combination”), unless immediately following such Business Combination: (A) more than 50% of the total voting power of (x) the corporation or other entity resulting from such Business Combination (the “Surviving Corporation”), or (y) if applicable, the ultimate parent corporation or other entity that, directly or indirectly, has beneficial ownership of at least 95% of the voting securities eligible to elect directors (or persons performing similar functions) of the Surviving Corporation (the “Parent Corporation”), is represented by Company Voting Securities that were outstanding immediately prior to such Business Combination (or, if applicable, is represented by voting securities into which such Company Voting Securities were converted or for which such Company Voting Securities were exchanged pursuant to such Business Combination), and such voting power of the Parent Corporation (or, if there is no Parent Corporation, the Surviving Corporation) among the holders thereof is held in substantially the same proportion as the voting power of such Company Voting Securities held by the holders thereof immediately prior to the Business Combination, (B) no person (other than any employee benefit plan (or related trust) sponsored or maintained by the Surviving Corporation or the Parent Corporation, as the case may be, or any Subsidiary thereof), is or becomes the beneficial owner, directly or indirectly, of 25% or more of the total voting power of the outstanding voting securities eligible to elect directors (or persons performing similar functions) of the Parent Corporation (or, if there is no Parent Corporation, the Surviving Corporation) and (C) at least a majority of the members of the board of directors (or similar governing body) of the Parent Corporation (or, if there is no Parent Corporation, the Surviving Corporation) following the consummation of the Business Combination were Incumbent Directors at the time of the Board’s approval of the execution of the initial agreement providing for such Business Combination or, if any director was elected after such time but prior to the consummation of such Business Combination, such director was elected to fill a vacancy on the Board created in the ordinary course and qualifies as an Incumbent Director (any Business Combination which satisfies all of the criteria specified in (A), (B) and (C) above shall be deemed to be a “Non-Qualifying Transaction”); or
(iv) the consummation of a complete liquidation or dissolution of the Company required to be approved by the Company’s shareholders or a sale of all or substantially all of the assets of the Company and its Subsidiaries, considered as a whole.
Notwithstanding the foregoing, a Change in Control of the Company shall not be deemed to occur solely because any person acquires beneficial ownership of more than 25% of the Company Voting Securities as a result of the acquisition of Company Voting Securities by the Company which reduces the number of Company Voting Securities outstanding; provided, that if after such acquisition by the Company such person becomes the beneficial owner of additional Company Voting Securities that increases the percentage of outstanding Company Voting Securities beneficially owned by such person, a Change in Control of the Company shall then occur.
(h) “Code” means the Internal Revenue Code of 1986, as amended from time to time.
(i) “Committee” means the Non-Qualified Plan Committee of the Company, whose members are appointed from time to time by the Board of Directors or the Chief Executive of the Company.
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(j) “Company” means Energy Future Holdings Corp., its successors and assigns.
(k) “Company Stock” shall mean shares of common stock of the Company, having no par value.
(l) “Deferral” means the deferral of Salary, Bonus and/or DICP Amounts under this Plan as provided for in Section 4 hereof.
(m) “Deferral Period” means the period of deferral, beginning with the first day of the applicable Plan Year, which shall be seven years for the Seven Year Option and which shall be the period ending with Retirement for the Retirement Option (or six months thereafter with respect to specified employees as provided under Section 8.3). Notwithstanding the foregoing, the Deferral Period shall end on the date of death, Disability, or Separation from Service (or six months thereafter with respect to specified employees as provided under Section 8.3) and, to the extent that amounts otherwise eligible for distribution under this Plan combined with the Participant’s other remuneration exceeds the Applicable Employee Remuneration for such year, the Deferral Period for such excess amount shall end with Retirement or such earlier date as of which such amounts, or any part thereof, combined with other remuneration does not exceed the Applicable Employee Remuneration. For purposes of this definition, “Applicable Employee Remuneration” means applicable employee remuneration as that term is defined in Section 162(m), or any successor provision, of the Code. Transition Provision: Notwithstanding any other provisions contained herein, the Deferral Period for amounts subject to an Election made for periods prior to April 1, 1998, shall be the Deferral Period applicable at the time of the Election.
(n) “DICP” means the EFH Deferred and Incentive Compensation Plan, as it may be amended from time to time.
(o) “DICP Amounts” means amounts deferred to this Plan prior to January 1, 2006, which would have been distributed under the DICP if not for the deferral of such amounts hereunder.
(p) “Disability” means a medically determinable physical or mental impairment that can be expected to last for a continuous period of not less than 12 months, as a result of which the Participant is entitled to receive, and has been receiving for a period of not less than three months, income replacement benefits under one or more plans of the Company.
(q) “Early Retirement” means Retirement at age fifty-five or later but prior to Normal Retirement.
(r) “EFH Stock Fund Account” shall mean the notional subaccount established on behalf of a Participant with respect to the portion of such Participant’s Account as is designated pursuant to Section 6.3 to be deemed invested in Company Stock.
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(s) “EFH Stock Fund Account Distribution Event” shall mean the earliest to occur of any of the following change in control events: (i) any one person, or more than one person acting as a group (as determined in accordance with Treasury Regulation Section 1.409A-3(i)(5)(v)(B)) (a “Person”), acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such person or persons) assets of the Company that have a total gross fair market value of 90 percent or more of the gross fair market value of all the assets of the Company immediately before such acquisition or acquisitions (subject, however, to the limitations of Treasury Regulation Section 1.409A-3(i)(5)(vii)(B)); (ii) any Person acquires ownership of capital stock of the Company that, together with stock held by such Person, constitutes more than 50 percent of the total fair market value or total voting power of the stock of the Company;or (iii) a majority of members of the Company’s Board of Directors is replaced during any 12-month period by directors whose appointment or election is not endorsed by a majority of the members of the Company’s Board of Directors before the date of the appointment or election; provided, however, that in the case of clauses (i) and (ii), an EFH Stock Fund Account Distribution Event shall not be deemed to occur unless such event results in such Person gaining control of more seats on the Company’s Board of Directors than the Sponsor Group.
(t) “Eligible Employee” shall mean an employee of a Participating Employer whose Salary, as of October 1 of the previous year, meets or exceeds a threshold Salary level (which shall not be less than $100,000) and/or other criteria established by the Plan Administrator for each Plan Year based on such factors as the Plan Administrator deems appropriate. Neither individuals whose benefit under the Plan have been transferred to the Oncor Plan, nor members of the SPC, shall be Eligible Employees hereunder.
(u) “Management Stockholder’s Agreement” shall mean the form of Management Stockholder’s Agreement, to be entered into between the Company and the Management Stockholders (as defined in the Management Stockholder’s Agreement), relating to investment in Company Stock and options for Company Stock.
(v) “Matching Award” means matching contributions made by the Participating Employers pursuant to section 5.1 of the Plan.
(w) “Normal Retirement” means Retirement at age sixty-two or later.
(x) “Participant” means an Eligible Employee who elects to participate in the Plan and whose Account(s) has not been completely distributed; provided, however, that “Participant” shall not include any individual whose benefit under this Plan has been assumed by the Oncor Plan.
(y) “Participating Employer” means the Company and each of its subsidiaries, affiliates or Business Units which are approved by the Committee for participation in this Plan. The Participating Employers, as of the date of the restatement of this Plan, are listed on Exhibit “A” attached hereto. Participation in the Plan by additional Participating Employers will commence as of the beginning of the Plan Year following Committee approval of such participation.
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(z) “Plan Administrator” means the person(s) or entities appointed by the Committee to assist in carrying out the operation of the Plan.
(aa) “Plan Year” means the twelve-month period beginning January 1 and ending December 31.
(bb) “Rate” means the earnings rate to be applied to certain Deferrals and Matching Awards under Section 6.2 and pursuant to Section 9.1 hereof for the Deferral Period which shall be the greater of: (i) the actual earnings rate, as determined by the Trustee, for assets held in Trust under the Seven-Year Option and invested in accordance with the provisions of Section 6.2; and (ii) the Alternative Rate. The term “Alternative Rate” shall mean the average earnings rate, as determined by the Trustee, of interest rates payable on Treasury Notes of the United States Government with a maturity period of ten years. Income credited under the Alternative Rate shall be determined by multiplying the Alternative Rate for the Plan Year within the Deferral Period times the average balance in the Account for such Plan Year, including income earned for prior periods. Income on all Accounts under the Plan shall be deemed to have been earned on a consistent basis.
(cc) “Retirement” means termination of employment from a Participating Employer upon attaining age 65, or as early as attaining age 55 with at least 16 years of Service.
(dd) “Retirement Option” means the option to defer receipt of certain amounts of Salary, Bonus and/or DICP Amounts until Retirement.
(ee) “Salary” means the annualized rate of normal base pay earnings, prior to any deferrals, of an Employee exclusive of overtime, bonuses or any fringe benefits.
(ff) “Sale Participation Agreement” shall mean the form of Sale Participation Agreement, to be entered into between Texas Energy Future Holdings Limited Partnership and the Management Stockholders, relating to investment in Company Stock and options for Company Stock.
(gg) “Separation from Service” means termination of employment under circumstances that would qualify as a “separation from service” for purposes of Code Section 409A and the regulations issued thereunder.
(hh) “Service” shall mean the aggregate period of employment of a Participant with all Participating Employers, determined on an elapsed time basis.
(ii) “Seven Year Option” means the option to defer receipt of certain amounts of Salary, Bonus and/or DICP Amounts for seven years.
(jj) “SPC” means the Strategy and Policy Committee of the Company, whose members are appointed from time to time by the Chief Executive of the Company.
(kk) “Sponsor Group” shall mean investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P., TPG Capital, L.P. and Goldman, Sachs & Co., who contributed certain funds to Texas Energy Future Holdings Limited Partnership, a Delaware limited partnership, in exchange for limited partnership units.
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(ll) “Trust” means the trust(s) established by the Company to assist it in meeting its obligations under the Plan.
(mm) “Trustee” means the trustee appointed by the Committee to hold assets of the Plan.
(nn) “Unforeseeable Emergency” means a severe financial hardship to a Participant resulting from an illness or accident of the Participant, the Participant’s spouse or a dependent (as defined in Code section 152(a)) of a Participant, loss of the Participant’s property due to casualty, or other similar extraordinary and unforeseeable circumstance arising as a result of events beyond the control of the Participant.
(oo) “Valuation Date” means each date as of which the Board of Directors certifies the value of one share of Company Stock, which certification shall be final and binding on all interested parties.
(pp) “Vesting Period” means the period beginning with the date of the beginning of the Plan Year of deferral and ending with the end of the seventh Plan Year.
Section 3.Deferral Eligibility and Participation
3.1Eligibility. An Eligible Employee shall be eligible to participate in the Plan as of the date that he satisfies the eligibility requirements set forth herein. All Eligible Employees will be given the opportunity, annually during an election period prior to the beginning of a Plan Year, to participate in the Plan during such Plan Year. Additionally, an Eligible Employee may elect, irrevocably, by written notice to the Plan Administrator on an election form, at the time(s), and in the manner prescribed by the Plan Administrator, to make DICP Deferrals under the Retirement Option, the Seven Year Option, or a combination thereof, in one percent (1%) increments up to a maximum of one hundred percent (100%) of DICP Amounts; provided that such DICP Deferral election is made at least twelve months prior to the date that such amounts would otherwise mature under the DICP, and provided further that this sentence shall apply only to amounts that would otherwise mature under the DICP prior to January 1, 2006. Individuals who first become Eligible Employees during the Plan Year shall be notified of their eligibility and shall be given the opportunity, during the thirty (30) day period following the date of initial eligibility, to participate in the Plan for the remainder of such Plan Year. Elections with regard to participation during a Plan Year shall be irrevocable.
3.2Participation. All Eligible Employees may elect to participate in this Plan, and defer Salary and Bonus and/or DICP Amounts in the manner prescribed in Section 4.1 below.
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Section 4.Election to Defer
4.1Deferral Election. An Eligible Employee may elect, irrevocably, by written notice to the Plan Administrator on an election form at the time(s), and in the manner prescribed by the Plan Administrator, to make Deferrals during the Plan Year of a percentage of Salary and/or Bonus, under the Retirement Option, the Seven Year Option, or a combination thereof, in one percent (1%) increments, up to a maximum of fifty percent (50%) of Salary and eighty-five percent (85%) of Bonus. Such election shall be made by an individual who first becomes eligible, during the period specified in Section 3.1, and by all other Participants during the election period prescribed by the Plan Administrator, which shall be, prior to the first day of the Plan Year to which such election relates.
4.2Salary Deferrals. Salary deferred under the Plan will be ratably deducted in each pay period during the Plan Year.
4.3Bonus Deferrals. Bonus deferred under the Plan will be deferred at the time that the Bonus would otherwise have been paid.
4.4Deferrals of DICP Amounts. Amounts which would otherwise mature under the DICP but are deferred hereunder prior to January 1, 2006, will be deferred immediately prior to the time that such amounts would otherwise mature under the terms of the DICP.
Section 5.Matching Awards, Vesting and Forfeitures
5.1Matching Awards. Prior to each Plan year, the SPC, within its sole discretion, shall determine whether each Participating Employer shall be required to contribute to the Account of each Participant employed by such Participating Employer a Matching Award equal to a percentage of the Participant’s Salary Deferral for that Plan Year and, if applicable, the amount of the Matching Award for that Plan Year. Any Matching Award shall be credited at the time of the crediting of the Salary Deferral amount to be matched.
5.2Vesting. Subject to the forfeiture provisions of Section 5.3, a Participant shall at all times be one hundred percent (100%) vested in the Participant’s Salary Deferrals, Bonus Deferrals, DICP Amounts and all earnings thereon. A Participant shall be one hundred percent (100%) vested in the Participant’s Matching Awards, and on income earned on such Matching Awards at the end of the Vesting Period. Notwithstanding any other provision of this Plan, a Participant’s Account shall become one hundred percent (100%) vested upon the Participant’s Normal Retirement, death, or Disability regardless of the applicable Vesting Period.
5.3Forfeitures. The following amounts shall be forfeited from a Participant’s Account as of the date upon which the forfeiture is created:
(a)Seven Year Option Forfeitures.
(i)Early Retirement. An amount equal to four percent (4%) of the portion of the Participant’s Account balance relating to Matching Awards and earnings thereon, and Salary Deferrals subject to Matching Awards and earnings thereon, for each full year Retirement occurs prior to Normal Retirement shall be forfeited.
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(ii)Termination for other than Death, Disability or Retirement. If termination of service with the Company occurs for reasons other than death, Disability, or Retirement, Matching Awards and all earnings thereon shall be forfeited.
(b)Retirement Option Forfeitures.
(i)Early Retirement. An amount equal to four percent (4%) of the Participant’s Account balance relating to non-vested Matching Awards and earnings thereon, and Salary Deferrals subject to Matching Awards and earnings thereon, for each full year Retirement occurs prior to Normal Retirement shall be forfeited.
(ii)Termination for other than Death, Disability or Retirement. If termination of service with the Company occurs for reasons other than death, Disability, or Retirement, Matching Awards and all earnings thereon for Plan Years which are nonvested, shall be forfeited.
Section 6.Investments and Earnings
6.1Investments and Earnings For Deferrals and Matching Awards After April 1, 1998. With respect to the portion of a Participant’s Account relating to Salary and Bonus Deferrals and Matching Awards made from and after April 1, 1998, and DICP Amounts previously deferred hereunder, the amount credited to a Participant’s Account shall be adjusted as of each Adjustment Date to reflect such gain, loss and/or expenses incurred based on the experience of the investments selected by the Participant prior to the date prescribed by the Committee for the investment of his or her Account and taking into account additional Deferrals credited to and distributions made from such Account since the last Adjustment Date. The Committee shall have sole and absolute discretion with respect to the number and type of investment choices made available for selection by Participants, the timing and manner of Participant investment elections and the method by which adjustments are made. The designation of investment choices by the Committee shall be for the sole purpose of adjusting Accounts pursuant to this Section and this provision shall not obligate the Participating Employers to invest or set aside any assets for the payment of benefits hereunder; provided, however, that a Participating Employer may invest a portion of its general assets in investments, including investments which are the same as or similar to the investment choices designated by the Committee and selected by Participants, but any such investments shall remain part of the general assets of such Participating Employer and shall not be deemed or construed to grant a property interest of any kind to any Participant, designated beneficiary or estate. The Committee shall notify the Participants of the investment choices available and the procedures for making and changing investment elections.
6.2Investments and Earnings For Deferrals and Matching Awards Made Prior to April 1, 1998. With respect to the portion of a Participant’s Account relating to Salary Deferrals and Matching Awards made prior to April 1, 1998 under the Seven Year Option, together with all earnings on such Salary Deferrals and Matching Awards, the Trustee shall continue to invest such amounts in a fixed income fund of investment grade securities under investment guidelines established by the Committee. The Trustee shall continue to invest all other contributions to Participants’ Accounts made prior to April 1, 1998 in a manner consistent with investment guidelines established by the Committee. At the time of distribution of the portion of Accounts attributable to Salary Deferrals and Matching Awards made prior to April 1, 1998, Participants will receive their Account balances relating to such pre-April 1, 1998 Salary Deferrals and Matching Awards, including income determined by applying the Rate.
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6.3Special One-Time Election for Notional Investment in Company Stock.
(a) Notwithstanding any other provision of the Plan to the contrary, the Plan Administrator shall provide to those Participants who satisfy the eligibility requirements of Section 6.3(b) the opportunity to make a special investment election whereby all or a specified portion of such Participant’s vested Account shall, effective as of December 28, 2007, be deemed to be invested in Company Stock. Such election shall be made in such manner as is consistent with the transition relief contained in Section 3.02 of Internal Revenue Service Notice 2007-86, to the extent such election, and the terms and conditions of this Section 6.3, impact the form and timing of payment of amounts so invested. Such elections shall be effected pursuant to election forms, shall be made within the election period specified below, and shall be subject to other requirements as may be approved by the Plan Administrator.
(b) Deemed investment elections under this Section 6.3 shall be permitted only with respect to Participants who, as of December 28, 2007: (i) are eligible to participate in the 2007 Stock Incentive Plan for Employees of Energy Future Holdings Corp.; and (ii) have not elected to take a special distribution pursuant to Section 8.6 of the Plan. Any such elections must be made on or before December 28, 2007, and shall only be effective with respect to amounts that would not have otherwise become distributable under the Plan in 2007.
(c) Any amounts designated by a Participant as deemed invested in Company Stock by virtue of the special election permitted under this Section 6.3 shall be reallocated from its current deemed investment to such Participant’s EFH Stock Fund Account and shall be deemed invested in Company Stock effective as of such time as designated by the Plan Administrator and communicated to Participants. Amounts so designated shall be taken first from the vested portion of such Participant’s Account that is subject to the Seven-Year Option and thereafter from the vested portion of such Participant’s Account as is subject to the Retirement Option, in each case, in the order in which such amounts were first deferred to the Plan.
(d) All amounts held in a Participant’s EFH Stock Fund Account shall remain a deemed investment in Company Stock (and may not be redirected or reinvested by the Participant), except that such amounts may be (or shall be, to the extent required) redirected into other investment options under the Plan upon the occurrence of events as described in the Management Stockholder’s Agreement or the Sale Participation Agreement that would otherwise permit (or require) a transfer of such Company Stock had the Participant been the holder of such Company Stock as of the date such Participant elected, pursuant to this Section 6.3, to designate Company Stock as a deemed investment hereunder, or where the repurchase by the Company of some or all of the Participant’s deemed investment in Company Stock under the Plan has been duly authorized by action of the Company or its designee. Upon any such required redirection, if the Participant has not redirected the investment of such amounts with such period as determined by the Plan Administrator after being notified of such required reinvestment, the Plan Administrator may hold such amounts in cash pending receipt of such Participant’s reinvestment direction. Any amount redirected, however, although no longer deemed invested in Company Stock, shall nonetheless remain allocated to the Participant’s EFH Stock Fund Account for purposes of determining the form and timing of distribution with respect to such amounts. For the sake of clarification, any reinvestment right or obligation under this Section 6.3(d) shall apply only with respect to a number of shares of Company Stock deemed held in such Participant’s EFH Stock Fund Account equal to the total number of shares that would have been permitted or required to be sold by the Participant, assuming the Participant had actually held such shares of Company Stock directly for investment by such Participant outside of the Plan and Participant otherwise held no other shares of Company Stock, upon the occurrence of the event as described in the Management Stockholder’s Agreement or the Sale Participation Agreement that would otherwise permit (or require) a transfer or liquidation of Company Stock.
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(e) The distribution of amounts allocated to a Participant’s EFH Stock Fund Account shall be governed exclusively by the provisions of this Section 6.3, and not by the provisions of Article 8. Upon the earlier to occur of a Separation from Service or an EFH Stock Fund Account Distribution Event (the “Applicable Payment Event”), the Participant’s EFH Stock Fund Account shall become distributable to the Participant. Such amount shall be distributed in the form of (i) with respect to the portion, if any, of the EFH Stock Fund Account that is deemed invested in Company Stock at the time of the distribution, either in shares of Company Stock or cash, or any combination thereof, as determined by the Company within its sole discretion; or (ii) in cash, with respect to the portion, if any, of the EFH Stock Fund Account that has been reallocated into any investment option other than Company Stock, as provided in Section 6.2(d). Such distribution shall be made in a single lump sum to the Participant within 60 days of the Applicable Payment Event; provided, however, that in no event shall payment be made later than the last day of the calendar year in which the Applicable Payment Event occurs, or if later, the fifteenth (15th) day of the third month following the date of the Applicable Payment Event. Such distribution shall be reduced by the amount of any otherwise applicable withholding or employment taxes. The amount of applicable withholding will be calculated at the rate applicable to supplemental earnings with respect to such Participant, and may be charged against the portion of the Participant’s EFH Stock Fund Account that is distributed in cash or shares of Company Stock in such proportion as the Plan Administrator may determine in its sole discretion. The value of a share of Company Stock for purposes of calculating any amounts withheld from a distribution, or the cash payable in lieu of shares as described in clause (i) of this Section 6(e), shall be based upon the Valuation Date immediately preceding, or concurrent with, the Applicable Payment Event.
(f) In the event a Participant receives a distribution of shares of Company Stock pursuant to Section 6.3(e) above, such Participant shall hold such shares subject to the terms of the Management Stockholder’s Agreement and the Sale Participation Agreement, and for purposes of applying the terms and conditions of the Management Stockholder’s Agreement and Sale Participation Agreement, such Company Stock shall be deemed to have been purchased by the Participant on December 28, 2007. Notwithstanding the foregoing, and in addition to any transfer restrictions imposed by the Management Stockholder’s Agreement and Sale Participation Agreement, a Participant receiving a distribution of Company Stock shall not transfer any of such shares during the period commencing on the date of the distribution and ending six (6) months thereafter. By designating an investment in Company Stock pursuant to this Section 6.3, a Participant shall be deemed to have consented to be bound by the terms and conditions of the Management Stockholder’s Agreement and Sale Participation Agreement, regardless of whether such Participant has executed such agreements.
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(g) The Plan Administrator, within its sole discretion, may require any Participant who makes a deemed investment election under this Section 6.3 to execute such documents or other agreements, including without limitation the Management Stockholder’s Agreement and/or the Sale Participation Agreement, that the Plan Administrator deems appropriate or necessary to ensure that the investment in Company Stock is administered consistent with the terms of the Plan, the requirements of Code Section 409A, and the intent of the Company in allowing the election described in this Section 6.3.
Section 7.Participant Accounts
7.1Separate Accounts. The Plan Administrator shall establish and maintain separate individual Accounts for each Participant for deferrals of Salary, Bonus and DICP Amounts, Matching Awards and earnings thereon for each Plan Year.
7.2Unsecured Interest. No Participant or Beneficiary shall have any security interest whatsoever in any assets of the Company or any Participating Employer. To the extent that any person acquires a right to receive payments under the Plan, such right shall not be secured or represented by any assets of the Company or any Participating Employer.
Section 8.Distribution of Accounts
8.1Value of Participant’s Accounts.
(a)Deferrals and Matching Awards Made On or After April 1, 1998. The value of the portion of a Participant’s Account relating to Salary and Bonus Deferrals and Matching Awards made on or after April 1, 1998, and deferrals of DICP Amounts, shall be determined based upon the amount credited to such Account as of the most recent Adjustment Date plus any Deferrals and Matching Awards credited to such Account since such Adjustment Date.
(b)Deferrals and Matching Awards Made Prior to April 1, 1998. The value of the portion of a Participant’s Account relating to Salary Deferrals and Matching Awards made prior to April 1, 1998 shall be determined as of the last day of the applicable Deferral Period.
(c)Reduction of Accounts Upon Distributions and Forfeitures. The amount of each distribution made with respect to an Account and any forfeiture amounts applied pursuant to Section 5.2 shall be deducted from the balance credited to such Account at the time of distribution or forfeiture.
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(d)Offset of Benefit Provided Under Qualified Retirement Plan. Notwithstanding any other provision of this Plan, the amount of a Participant’s benefit as otherwise determined under this Plan as of September 30, 2009, (or, if less, the balance as of December 31, 2009), shall be offset by the lump sum benefit provided to such Participant (if any) under Section 7.5 of the EFH Retirement Plan and specified in Part (II) of Appendix F thereof. Such offset shall be applied first to the portion of a Participant’s Account that is subject to the Retirement Option form of payment as described in Section 8.2(b), and second, to the portion of a Participant’s Account subject to the Seven-Year Option (beginning with the portion of the account that was most recently deferred and that therefore would be otherwise subject to distribution from this Plan at the latest time). Such offset shall finally be applied to offset the amount credited to the Participant’s EFH Stock Fund Account, but only to the extent the amount subject to reduction is no longer deemed invested in Company Stock.
8.2Form and Timing of Distribution. The value of the Participant’s Accounts at distribution shall be paid in cash, as follows:
(a)Seven-Year Option - in a lump-sum distribution as soon as practicable after the end of the Deferral Period, but in no event later than sixty days following such date. The portion of the Participant’s Account subject to distribution hereunder shall be valued as of the end of the Deferral Period and shall not earn interest or be otherwise adjusted for earnings for the period from the end of the Deferral Period to the date of distribution.
(b)Retirement Option -
(i)Form of Payment upon Retirement - The aggregate amounts deferred under the Retirement Option, together with any matching contribution or earnings attributable thereto, shall be distributed in a single annual installment, or in annual installments over the period certain elected by the Participant as provided in Section 8.2(b)(iii) from two to ten years, or fifteen years, or twenty years, commencing in the year after, but in no event later than twelve months following the date of Retirement, subject, however, to the delay provided for in Section 8.3. During the distribution period, undistributed amounts in the Retirement Option shall continue to be adjusted for earnings pursuant to Section 8.2(b)(iv). In the event of the death of a Participant or Beneficiary during the distribution period, the remainder of the Account shall be distributed to the Participant’s Beneficiary, or if no Beneficiary has been designated, to the estate of the Participant or Beneficiary in a lump-sum distribution as soon as practicable after the Participant’s date of death.
(ii)If Participant Terminates - If the Participant terminates employment prior to Retirement, then the portion of his Account subject to the Retirement Option shall be paid in a lump-sum distribution as soon as practicable after the end of the Deferral Period, but in no event later than sixty days following such date. The portion of the Participant’s Account subject to distribution hereunder shall be valued as of the end of the Deferral Period and shall not earn interest or be otherwise adjusted for earnings for the period from the end of the Deferral Period to the date of distribution.
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(iii)Election of Payment Term - Each Participant shall elect the period over which amounts in such Participant’s Account subject to the Retirement Option shall be paid. Except as provided for in Section 8.2(b)(iv) below, such election shall be made on or before the date the Participant first commences participation in the Plan. Such election shall apply to the entire portion (if any) of the Participant’s Account that is subject to the Retirement Option, regardless of when such amounts were deferred or otherwise credited to the Participant’s Account, and shall be irrevocable.
(iv)Special Distribution Elections - Notwithstanding the provisions of paragraph (iii) above, Participants shall be entitled to make a distribution election (or elections) at such time or times as determined by the Plan Administrator consistent with Code Section 409A and the rules and regulations issued thereunder with respect to all accounts deferred under the Plan before and after such election(s), and such election(s) shall, to the extent determined by the Plan Administrator consistent with Code Section 409A and the rules and regulations issued thereunder, supersede any other elections previously made by the Participant.
(v)Earnings During Distribution Period - With respect to the portion of the Participant’s Account relating to Salary, Matching Awards and Bonus Deferrals made on or after April 1, 1998 and DICP Amounts, the Participant may, within 60 days of Retirement, in accordance with administrative procedures established by the Plan Administrator, elect to have all or a portion of his or her Account allocated, in increments of 1%, to a Fixed Annuity Fund (“Fixed Annuity”), which shall be credited a fixed rate of interest throughout the Retirement distribution period. This rate will equal the Fixed Account rate in effect at the time of Retirement. Any amounts not allocated to a Fixed Annuity by the end of such 60-day period shall earn a variable annuity rate of return taking into account the earnings and losses credited to the Participant’s Account as a result of the investment return tracking elections made by the Participant during the annuity period (“Variable Annuity”). Except as otherwise provided in Section 9.2, with respect to the portion of the Participant’s Account relating to Salary Deferrals and Matching Awards made prior to April 1, 1998, such installments shall be made in a fixed amount which shall amortize the value of such portion of the Participant’s Account over the period elected by the Participant in Section 8.2(b)(iii), using the Rate as a projected earnings rate of return.
(c)DICP Amounts. DICP Amounts that are deferred to the Plan prior to January 1, 2006 shall not be payable earlier than the later of (i) the date such amounts would otherwise become payable hereunder, or (ii) the date that is five (5) years after the date that such amounts were deferred to this Plan under Section 4.4.
8.3Delay of Certain Benefit Payments.
(a) With respect to any Participant who is a “specified employee” (within the meaning of Code section 409A and the regulations issued thereunder), the distribution of any benefits shall not commence earlier than the date that is six (6) months following the date of such Participant’s Separation from Service. In the event that any benefit payable in installments is delayed by application of this Section 8.3(a), the period of payment shall not be extended, the first payment shall include all amounts that would have otherwise been paid in the absence of such delay, and subsequent payments shall be made at such times and in such amounts as would have otherwise been paid in the absence of such delay.
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(b) The provisions of Section 8.3(a) shall not apply (i) with respect to any distribution made on account of the death or Disability of the Participant, or (ii) if, at the time of such Participant’s Separation from Service, no stock of either the Company or the Participant’s employer is publicly traded on an established securities market or otherwise.
8.4Election to Delay Commencement of Retirement Option Payments.
Any Participant may make a one-time election to delay the commencement of payment of that portion of his Account that is subject to the Retirement Option payment provisions of Section 8.2(b), subject to the following:
(a) Such election shall be made no later than twelve (12) months prior to the date on which such payments would have otherwise commenced (without regard to the application of Section 8.3), and
(b) Such election must specify a payment date that will cause the commencement of the payment of such amounts to be delayed for at least five (5) years beyond the date such payments would have otherwise commenced in the absence of the election under this Section 8.4.
(c) A Participant may make only one election under this Section 8.4 during the period of his participation in the Plan and such election will be ineffective until the expiration of twelve (12) months after the date it is made.
(d) An election under this Section 8.4 shall not be effective with respect to any amount subject to the Retirement Option that is payable as a lump sum under Section 8.2(b)(ii).
8.5Distribution in the Event of an Unforeseeable Emergency. If a Participant encounters an Unforeseeable Emergency, the Plan Administrator in its absolute discretion may direct the Company to pay to such Participant such portion of the Account, including the entire amount if appropriate, as the Committee shall determine to be necessary to satisfy the need presented by such Unforeseeable Emergency, plus amounts necessary to pay all taxes and penalties reasonably anticipated as a result of the distribution. A distribution on account of an Unforeseeable Emergency may not be made to the extent such emergency may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the Participant’s assets (to the extent the liquidation would not itself cause severe financial hardship).
8.6Special Payment Election(s). Effective as of December 4, 2007, and notwithstanding any other provision of the Plan to the contrary, Participants who would be otherwise eligible to make an election under Section 6.3 or 6.4 of the Plan, will have the opportunity to make a special election or elections regarding the form and/or timing of the payment of amounts previously deferred under the Plan, consistent with the transition relief contained in Section 3.02 of Internal Revenue Service Notice 2007-86. Such elections under Section 8.6 shall be effected pursuant to election forms, shall be within specified election periods, and shall be subject to other requirements as may be approved by the Plan Administrator. Additionally, such elections may specify the funds to which the elections may apply (including amounts subject to the Seven-Year Option, the Retirement Option, or both), and the method by which any distribution effected thereby shall be charged against the Participant’s Account under the Plan all as determined or permitted by the Plan Administrator in its sole discretion. This Section 8.6 shall be implemented and applied within the sole discretion of the Plan Administrator, and in no event shall any Participant have any right to demand a special payment election hereunder.
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Section 9.Certain Elections for Pre-April 1, 1998 Participants
9.1Election to Continue Under Prior Plan Provisions. Notwithstanding anything herein to the contrary, Eligible Employees who, as of March 31, 1998, were Participants in this Plan were given the opportunity, pursuant to a one-time, irrevocable written election, to have certain Plan provisions relating to permitted Deferrals, Matching Awards and investments which were in effect immediately prior to the effective date of the restatement of this Plan, as described in Exhibit “B” attached hereto and incorporated herein by reference (the “Prior Plan Provisions”), apply with respect to their future Plan participation.
9.2Election for Investment of Pre-April 1, 1998 Deferrals and Matching Awards. Notwithstanding anything herein to the contrary, Eligible Employees who, as of March 31, 1998, were Participants in this Plan and who do not make the election provided for in Section 9.1 to have the Prior Plan Provisions apply to their future Plan participation, were given the opportunity, pursuant to a one-time, irrevocable written election, to have the investment provisions set forth in Section 6.1 and the valuation provisions set forth in Section 8.1(a) apply to the entirety of their Account, including Salary Deferrals and Matching Awards made prior to April 1, 1998. The Account of each Participant who made such an election was valued as of March 31, 1998 using the actual rate of return of such Account assets in accordance with the investment provisions of Section 6.2. From and after April 1, 1998, the provisions of Sections 6.2 and 8.1(b) no longer applied to any portion of their Account. Furthermore, such Participant’s election under Section 8.2(b)(iv) shall be applied as if all amounts in Participant’s Account, subject to the Retirement Option, were deferred on or after April 1, 1998.
Section 10.Nontransferability
10.1Nontransferability. In no event shall the Company or any Participating Employer make any distribution or payment under this Plan to any assignee or creditor of a Participant or a Beneficiary. Prior to the time of a distribution or payment hereunder, a Participant or a Beneficiary shall have no right by way of anticipation or otherwise to assign or otherwise dispose of any interest under this Plan.
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Section 11.Designation of Beneficiaries
11.1Specified Beneficiary. A Participant shall designate a Beneficiary or Beneficiaries who, upon the Participant’s death are to receive the amounts that otherwise would have been paid to the Participant. All Beneficiary designations shall be in writing and signed by the Participant, and shall be effective only if and when delivered to the Plan Administrator during the lifetime of the Participant. A Participant may, from time to time during his lifetime, change his Beneficiary or Beneficiaries by a signed, written instrument delivered to the Plan Administrator. The payment of amounts shall be in accordance with the last unrevoked written designation of the Beneficiary that has been signed and so delivered.
11.2Estate as Beneficiary. If a Participant designates a Beneficiary without providing in the designation that the Beneficiary must be living at the time of each distribution, the designation shall vest in the Beneficiary all of the distributions whether payable before or after the Beneficiary’s death, and any distributions remaining upon the Beneficiary’s death shall be made to the Beneficiary’s estate. In the event a Participant shall not designate a Beneficiary or Beneficiaries, or if, for any reason, such designation shall be ineffective, in whole or in part, as determined solely in the discretion of the Plan Administrator, the distribution that otherwise would have been paid to such Participant shall be paid to the Participant’s estate.
Section 12.Rights of Participants
12.1Employment. Nothing in the Plan shall alter or interfere in any way with the employment relationship between Participants and Participating Employers, nor limit in any way the right of the Company or any Participating Employer to terminate any Participant’s employment at any time. This Plan shall not confer upon any Participant any right to continue in the employ of the Company or any Participating Employer.
Section 13.Administration
13.1Administration. The Committee shall be responsible for the administration of the Plan. The Committee is authorized, in its sole discretion, to interpret the Plan, to prescribe, amend, and rescind rules and regulations relating to the Plan, provide for conditions and assurances deemed necessary or advisable to protect the interests of the Company, and to make all other determinations necessary or advisable for the administration of the Plan. The determination of the Committee, interpretation or other action made or taken pursuant to the provisions of the Plan, shall be final and shall be binding and conclusive for all purposes and upon all persons whomsoever. The Committee shall appoint a Plan Administrator to assist in carrying out the operations of the Plan and a Trustee of the Trust to accompany the Plan.
13.2Annual Reports. The Plan Administrator shall render annually a written report to each Participant which shall set forth, at a minimum, the Participant’s Account balances as of the end of the most recent Plan Year.
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Section 14.Amendment or Termination of the Plan
14.1Amendment or Termination of the Plan. The Board of Directors may amend, terminate, or suspend the Plan at any time. Further, the Committee may amend the Plan at any time;provided, however, that the authority of the Committee to amend the Plan shall be limited to amendments consistent with the following criteria: (i) the amendment is administrative or ministerial in nature; (ii) the amendment does not result in a material change to the Plan’s funding or costs (a plan change is considered material if the amendment has a cost greater than $1 million to the Plan, as determined by the Committee in its sole discretion exercised in good faith); or (iii) the Plan amendment is dictated by statute or regulation. Any amendment, termination, or suspension of the Plan shall be effective on such date as the Board of Directors or the Committee, as applicable, may determine. An amendment or modification of the Plan may affect Participants at the time thereof as well as future Participants, but no amendment or modification of the Plan for any reason may diminish any Participant’s Accounts as of the effective date thereof except that an amendment may diminish a Participant’s benefit under this Plan to the extent a reasonably equivalent or more favorable benefit is made available to such Participant under another plan, policy or program of the Company. As soon as practical, but in no event more than fifteen (15) days following Plan termination, the Participating Employers shall make irrevocable contributions to the Trust in an aggregate amount, as determined by the Committee, which when added to the total value of the assets of the Trust at such time equals the total amount credited to all Accounts as of the date of Plan termination. In the event the Plan is terminated, no additional deferrals shall be permitted, and Participants’ Accounts shall be distributed at the time and in the manner that they would otherwise have been distributed under the Plan in the absence of such termination. In no event shall such termination result in the acceleration of benefit payments hereunder.
Section 15.Corporate Changes
15.1Dissolution or Liquidation. Notwithstanding any provision herein to the contrary, upon the dissolution of the Company in a transaction subject to taxation under Code section 331, the Participants’ Accounts shall vest as of the day preceding the date of dissolution or liquidation and shall not be subject to the forfeiture provisions of this Plan. The Company shall cause the full amount of each Participant’s Account to be paid in cash in a lump sum to the Participant, or his Beneficiary, as soon as is practicable, but in no event later than sixty days following the date of dissolution or liquidation.
15.2Change in Control. Notwithstanding anything in this Plan to the contrary, in the event of a Change in Control: (i) the Participants’ Accounts shall vest as of the day immediately preceding the date of such Change in Control and shall not be subject to the forfeiture provisions of this Plan, and (ii) the Participating Employers shall, as soon as possible, but in any event within thirty (30) days, following such Change in Control, make irrevocable contributions to the Trust in an aggregate amount which, when added to the total value of the assets of the Trust at such time, equals the total amount credited to all Accounts as of the date of such Change in Control. Thereafter, the Participating Employers shall make monthly contributions to the Trust in aggregate amounts sufficient to maintain the total value of Trust assets at an amount equal to the total amount credited to all Accounts. Notwithstanding any provision of this Plan to the contrary, no action taken on or within two years following such Change in Control to amend or terminate this Plan shall be effective unless written consent thereto is obtained from a majority of the Participants.
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15.3Funding Limitations. Notwithstanding Section 15.2 or any other provision of the Plan or the Trust to the contrary, the Plan Administrator may authorize the Trustee to make the following payments even if they would otherwise not be permitted by the Trust, and a Participating Employer may refrain from making any contributions or payments otherwise required or permitted to be made by the Plan or the Trust, to the extent necessary to satisfy the following requirements.
(a) No amount shall be set aside or reserved directly or indirectly (under the Trust or otherwise), during any restricted period (as defined in Section 409A(b)(3)(B) of the Code) for the purpose of paying a Benefit under the Plan to any Eligible Employee who is an applicable covered employee (as defined in Section 409A(b)(3)(D) of the Code). It is understood that a restricted period will generally occur in a Plan Year if any single-employer defined benefit plan (an “Applicable Plan”) maintained by the Company or any company that is in a controlled group that includes the Company (within the meaning of Sections 414(b) and (c) of the Code and guidance issued by the Internal Revenue Service) is “at risk” within the meaning of Section 430(i) of the Code for the preceding Plan Year. “Applicable covered employee” generally includes any Eligible Employee who is, with respect to the Company or any entity under common control with the Company, described in section 162(m)(3) of the Code or subject to the requirements of Section 16(a) of the Securities Exchange Act of 1934. All such persons are referred to herein as “Covered Employees.”
(b) The Plan Administrator shall monitor the funded status of each Applicable Plan and will determine whether a restricted period exists with respect to any such plan. If the Plan Administrator determines that a restricted period exists for a Plan Year, it shall determine whether any amount, including earnings, has been set aside or reserved during that period for the purpose of paying a benefit to any Covered Employee or would be set aside but for the action of the Plan Administrator. The Plan Administrator may request the Trustee to pay such amount to the Company or to any other person designated by the Plan Administrator or to otherwise segregate such amount from the assets of the Trust. The foregoing shall not apply, however, to the extent that the Company elects to treat the amount set aside or reserved as a transfer of property for tax purposes and taxable to the Covered Employee accordingly.
(c) Subject to any guidance issued by the Internal Revenue Service, the Plan Administrator may use any method it deems appropriate to calculate the amount set aside or reserved for any Covered Employee during a restricted period. The determination made by the Plan Administrator shall be binding on the Trustee and each Covered Employee and any person claiming any interest in or payment from the Trust related to such Covered Employee. The Plan Administrator may also utilize any program approved by the Internal Revenue Service to correct any amount that was improperly set aside under the Trust, and may adopt such rules and procedures as it deems necessary to comply with Section 409A(b)(3) of the Code.
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(d) The Plan Administrator shall maintain a record of any amount transferred from the Trust pursuant to paragraph (b), or that a Participating Employer does not contribute to the Trust. Such amount shall be credited with interest or earnings based on what would have been allocable to such amounts if they had been held in the Trust. Such amount shall be paid to the Trust as soon as possible after the Plan Administrator determines that no Applicable Plan remains in a restricted period. If any payment from the Trust to a Covered Employee or the Covered Employee’s beneficiary has been reduced or withheld as a result of the restrictions of this Section, such amount shall be paid to such employee in a lump sum as soon as possible after the amount contemplated in the foregoing sentence is paid to the Trustee. The Company may also make such payments directly.
(e) The purpose of this Section is to comply with the restrictions of Section 409A(b)(3) of the Code and shall be interpreted accordingly. This provision is intended to impose only those restrictions that are required by that Section and only on the persons covered by the Section. The Plan Administrator shall interpret and apply this Section accordingly.
Section 16.Requirements of Law
16.1Governing Law. The Plan is intended to satisfy the requirements of Code section 409A and the regulations issued thereunder, and shall be construed to that end. Except as otherwise preempted by Federal law, the Plan, and all agreements hereunder, shall be construed in accordance with and governed by the laws of the State of Texas.
Section 17.Withholding Taxes
17.1Withholding Taxes. The Company shall have the right to deduct from all cash payments under the Plan or from a Participant’s compensation an amount necessary to satisfy any federal, state, or local withholding tax requirements.
Section 18.Investment and Funding
18.1Trust. The benefits to be derived by Participants in the Plan will be funded through the Trust, provided, however, that any assets held by the Trust shall at all times be subject to the claims of judgment creditors of the Company.
18.2Funding of Trust. With respect to Deferrals made under the Seven Year Option, the Participating Employers shall, promptly after Deferrals are credited to Participants’ Accounts, provide the Trust with resources in amounts equal to the amounts of such Deferrals. With respect to Deferrals made under the Retirement Option, the Participating Employers shall fund the Trust through the purchase of corporate owned life insurance or such other Trust assets as may be determined by the Committee from time to time.
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18.3Distributions from Trust. If Trust assets allocated to any Participant’s Account for a Plan Year are less than the amount required to affect a distribution to such Participant provided for in this Plan, the applicable Participating Employer will pay such difference either through the Trust or directly to the Participant. If, after all obligations to Participants hereunder have been fully satisfied, there remain assets in the Trust, such excess amounts shall be returned to the Company.
18.4Funding and Distribution Requirements Under Certain Circumstances. The provisions of this Section 18 shall be subject to (and, if deemed to be contradicting, overridden by) the provisions of Section 15 of this Plan.
EXECUTED December 10, 2009, to be effective as of January 1, 2010.
| Energy Future Holdings Corp. | ||
| By: | /s/ Paul M. Keglevic | |
| Paul M. Keglevic, Executive Vice President & | ||
| Chief Financial Officer | ||
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EXHIBIT “A”
PARTICIPATING EMPLOYERS
As of January 1, 2010
EFH Corp. and each of its direct and indirect
subsidiary companies, but excluding
Oncor Electric Delivery Company LLC
and its subsidiaries.
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EXHIBIT “B”
Prior Plan Provisions
The following provisions shall apply to all future Plan participation of Participants who make the one-time irrevocable election to continue to be governed by the Prior Plan Provisions in Section 9.1 of the Plan:
1.Deferral Election. The Participant may elect, irrevocably, by written notice to the Plan Administrator on an election form and in the manner prescribed by the Plan Administrator, to defer a percentage of Salary, in one percent (1%) increments not to exceed a maximum of ten percent (10%), during each Plan Year, in the Retirement Option, the Seven Year Option, or a combination thereof. Deferrals of Bonus shall not be permitted.
2.Matching Awards. The Company shall contribute to each Participant’s Account, as a Matching Award, an amount equal to one hundred percent (100%) of the amount of Salary deferred by the Participant. Such contribution shall be credited at the time of the crediting of the Salary Deferral amount to be matched.
3.Investments, Earnings and Valuation.
(a) The Trustee shall invest, as soon as administratively feasible, all contributions received for Accounts held in Trust under the Seven Year Option of the Plan in a fixed income fund of investment grade securities under investment guidelines established by the Committee. Interest received on the investments shall be reinvested in such fund. All other contributions shall be invested in accordance with investment guidelines established by the Committee.
(b) At the time of distribution, the Participant will receive his Account balance including income determined by applying the Rate.
(c) The total of all assets held by the Trustee for Accounts held in Trust will be deemed held in an unsegregated fund for valuation purposes. Each month the Trustee shall determine the value of each unit by dividing the current value of the fund by the total number of units held in all such Accounts. The value of Accounts held in Trust under the Retirement Option of the Plan shall be determined in the same manner as amounts deferred under the Seven Year Option of the Plan.
4.Forfeitures. The following provisions shall apply with respect to forfeitures in lieu of the provisions of Section 5.3 of the Plan. The amounts described below shall be forfeited from an Account as of the date upon which the forfeiture is created:
(a)Seven Year Option Forfeitures.
(i)Early Retirement. An amount equal to four percent (4%) of the total Account balance for each full year Retirement occurs prior to Normal Retirement shall be forfeited.
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(ii)Termination for other than Death, Disability or Retirement. If termination of service with the Company occurs for reasons other than death, Disability, or Retirement, income on and contributions to the Matching Account shall be forfeited and income in excess of six percent (6%) per annum credited to Salary Deferrals shall be forfeited.
(b)Retirement Option Forfeitures.
(i)Early Retirement. An amount equal to four percent (4%) of the total Account balance for all non-vested Plan Years for each full year Retirement occurs prior to Normal Retirement shall be forfeited.
(ii)Termination for other than Death, Disability or Retirement. If termination of service with the Company occurs for reasons other than death, Disability, or Retirement, income earned on and contributions to the Matching Account, for Plan Years which are nonvested, shall be forfeited and income in excess of six percent (6%) per annum credited to Salary Deferrals shall be forfeited for all nonvested Plan Years.
5.Value of a Participant’s Account. The cash value of a Participant’s Account shall be determined as of the last day of the applicable Deferral Period, or, if earlier, at termination of employment.
6.Form and Timing of Distributions. The form and timing of distributions shall be subject to Section 8 of the Plan; provided, however, that the installments shall be in a fixed amount which shall amortize the value of the Participant’s Account in annual installments over the distribution period elected by the Participant under Section 8.2(b)(iii), using the Rate as a projected earnings rate of return.
7.Certain Inapplicable Provisions. The provisions of Sections 3, 4.1, 4.3, 5.1, 5.3, 6.1, 8.1(a) and 8.2(b)(iv) of the Plan shall not apply and shall be of no force or effect with respect to any portion of the Participant’s Account or his prior or future Plan participation. All of the remaining provisions of the Plan shall remain in full force and effect.
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Exhibit 10(ee)
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 February 19, 2009:
(1) Section 2.5 of the Plan is hereby amended in its entirety to read as follows:
“2.5 “Committee” shall mean the Non-Qualified Plan Committee whose members are appointed from time to time by the Board of Directors or the Chief Executive of the Company.”
(2) Section 5.1 of the Plan is hereby amended in its entirety to read as follows:
“5.1 The Board of Directors shall be vested with full power and authority to amend the Plan or to terminate the Plan at any time. Further, the Committee may amend the Plan at any time;provided, however,that the authority of the Committee to amend the Plan shall be limited to amendments consistent with the following criteria: (i) the amendment is administrative or ministerial in nature; (ii) the amendment does not result in a material change to the Plan’s funding or costs (a plan change is considered material if the amendment has a cost greater than $1 million to the Plan, as determined by the Committee in its sole discretion exercised in good faith); or (iii) the Plan amendment is dictated by statute or regulation. However, no act of amendment or termination shall reduce any Benefit accrued to the date such act is adopted. Furthermore, if the Plan is terminated, amended, or frozen or any other action is taken to limit future Benefit accruals under the Plan, or in the event of a Change in Control, each of the Participating Employers hall be obligated to take all action as may be provided for under the Trust Agreement, the Second Trust Agreement or any other agreement affecting, in any way, the funding and/or securitization and the current or future payment of Benefits.”
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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 31st day of July, 2009.
| ENERGY FUTURE HOLDINGS CORP. |
/s/ M. Rizwan Chand |
| M. Rizwan Chand, |
Executive Vice President, Human Resources & Administration |
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Exhibit 10(ff)
ENERGY FUTURE HOLDINGS CORP. KEY EMPLOYEE
NON-QUALIFIED STOCK OPTION AGREEMENT
THIS AGREEMENT (“Agreement”), dated as of December 17, 2009 (the “Effective Date”), is made by and between Energy Future Holdings Corp., a Texas corporation (hereinafter referred to as the “Company”), and the individual whose name is set forth on the signature page hereof (hereinafter referred to as the “Optionee”). Any capitalized terms used but not otherwise defined herein shall have the meaning set forth in the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates (the “Plan”).
WHEREAS, the Company wishes to carry out the Plan, the terms of which are hereby incorporated by reference and made a part of this Agreement; and
WHEREAS, the Organization and Compensation Committee of the Board of the Company (the “Committee”) has determined that it would be to the advantage and best interest of the Company and its shareholders to grant the Option provided for herein to the Optionee as an incentive for increased efforts during his term of employment with the Company or its Subsidiaries or Affiliates, and has advised the Company thereof and authorized the undersigned officers to issue said Option.
NOW, THEREFORE, in consideration of the mutual covenants herein contained and other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereto do hereby agree as follows:
ARTICLE I
DEFINITIONS
Whenever the following terms are used in this Agreement, they shall have the meaning specified below unless the context clearly indicates to the contrary.
Section 1.1Cause
“Cause” shall mean “Cause” as such term may be defined in any employment agreement or any change-in-control agreement in effect at the time of termination of employment between the Optionee and the Company or any of its Subsidiaries or Affiliates, or, if there is no such employment or change-in-control agreement, “Cause” shall mean, with respect to an Optionee: (i) if, in carrying out his duties to the Company, the Optionee engages in conduct that constitutes (a) a material breach of his fiduciary duty to the Company or its shareholders (including, without limitation a material breach or attempted breach of the restrictive covenants under the Management Stockholder’s Agreement), (b) gross neglect or (c) gross misconduct resulting in material economic harm to the Company, provided that any such conduct described in (a), (b) or (c) is not cured within ten (10) business days after the Optionee receives from the Company written notice thereof, or (ii) Optionee’s conviction of, or entry of a plea of guilty or nolo contendere for, a felony or other crime involving moral turpitude.
Section 1.2Closing Date
“Closing Date” shall mean October 10, 2007.
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Section 1.3Disability
“Disability” shall mean “Disability” as such term is defined in any employment agreement between the Optionee and the Company or any of its Subsidiaries, or, if there is no such employment agreement, “Disability” shall mean the Optionee’s physical or mental incapacitation and consequent inability for a period of six consecutive months to perform the Optionee’s duties;provided,however, in the event the Company temporarily replaces the Optionee, or transfers the Optionee’s duties or responsibilities to another individual, on account of the Optionee’s mental or physical impairment for a period of time which is covered by the Company’s short term disability plan, the Optionee’s employment shall not be deemed terminated by the Company and the Optionee shall not be able to resign with Good Reason.
Section 1.4Extended Exercise Date
“Extended Exercise Date” shall mean the earlier of: (i) the tenth anniversary of the applicable Grant Date; or (ii) the later of the date: (A) one hundred and eighty (180) days following the date of an Optionee’s termination of employment with the Company and all Service Recipients and (B) thirty (30) days following the first date on which the Optionee could exercise the Option, or any portion thereof, and immediately resell the Shares acquired upon such exercise for cash consideration.
Section 1.5Fair Market Value
“Fair Market Value” shall mean, for the purposes of the Plan and this Agreement and notwithstanding the definition contained in the Plan: (i) if there is a public market for the Shares on such date, the average of the high and low closing bid prices of the Shares on such stock exchange on which the Shares are principally trading on the date in question, or, if there were no sales on such date, on the closest preceding date on which there were sales of Shares or, (ii) if there is no public market for the Shares, on a per Share basis, the fair market value of the Common Stock on any given date, as determined reasonably and in good faith by the Board, which shall not take into account any minority interest discount and shall not take into account a discount for illiquidity of Shares held by an Optionee in excess of any illiquidity discount applicable to Shares generally; provided that if the Board’s determination under this clause (ii) is not based on a valuation completed by an independent valuation firm within the 6 months preceding the Board’s determination, the Optionee may require the Company to retain an independent valuation firm to determine the fair market value (and the Company will bear the cost of such appraisal, unless the appraised value is 110% or less of the fair market value as determined by the Board, in which case the Optionee will bear the cost of such appraisal).
Section 1.6Fiscal Year
“Fiscal Year” shall mean each of calendar year 2010, 2011, 2012, 2013, and 2014.
Section 1.7Good Reason
“Good Reason” shall mean “Good Reason” as such term may be defined in any employment agreement or any change-in-control agreement in effect at the time of termination of employment between the Optionee and the Company or any of its Subsidiaries or Affiliates, or, if there is no such employment or change-in-control agreement, “Good Reason” shall mean (i) a reduction in the Optionee’s base salary or the Optionee’s annual incentive compensation opportunity (other than a general reduction in base salary or annual incentive compensation opportunities that affects all salaried employees of the Company proportionately); (ii) a transfer of the Optionee’s primary workplace by more than thirty-five (35) miles from the current workplace; (iii) a substantial adverse change in the Optionee’s duties and responsibilities; (iv) any material breach by the Company of this Agreement, the Management Stockholder’s Agreement, or the Optionee’s employment agreement; or (v) an adverse change in the Optionee’s line of reporting to superior officers pursuant to the terms of his employment agreement or any change-in-control agreement;provided,however, that any isolated, insubstantial and inadvertent failure by the Company that is not in bad faith and is cured within ten (10) business days after the Optionee gives the Company written notice of any such event set forth above, shall not constitute Good Reason.
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Section 1.8Grant Date
“Grant Date” means the date of grant of the Option, or a portion thereof, which is specified for each of the Time Option and the Performance Option in Section 2.1 hereof.
Section 1.9Job Elimination
“Job Elimination” shall mean the termination of an Optionee’s employment without Cause by the Company or any of its Subsidiaries or Affiliates in either of Fiscal Year 2011 or 2012 due to the elimination of the Optionee’s job position, to the extent determined by the Chief Executive Officer and approved by the Committee that such elimination occurred.
Section 1.10Liquidity Event
“Liquidity Event” shall mean the first to occur of any transaction or completion of a series of transactions that results, directly or indirectly, in the Sponsor Group or their Affiliates realizing in respect of their Shares cash and/or publicly traded securities (includes Shares held by the Sponsor Group or their Affiliates, if then publicly traded and freely marketable securities) having a market value that at least equals the Sponsor Return or the Sponsor IRR, provided that if more than 25% of the aggregate amount realized is in the form of publicly traded securities, no portion of such excess may be taken into account in determining the Sponsor Return or Sponsor IRR until such securities are sold for cash in accordance with Section 3.1(c).
Section 1.11Management Stockholder’s Agreement
“Management Stockholder’s Agreement” shall mean that certain Management Stockholder’s Agreement between the Optionee and the Company.
Section 1.12Marketable Securities
“Marketable Securities” shall mean (i) prior to a public offering, the equity securities of any acquiring entity that gains control of the Company or (ii) the registered Shares of the Company following a public offering.
Section 1.13Measurement Date
“Measurement Date” shall mean any date upon which a Liquidity Event occurs.
Section 1.14Option
“Option” shall mean the aggregate of the Time Option and the Performance Option granted under Section 2.1 of the Agreement.
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Section 1.15Parent
“Parent” shall mean Texas Energy Future Holdings Limited Partnership, a Delaware Limited Partnership.
Section 1.16Performance Option
“Performance Option” shall have the meaning given such term in Section 2.1 hereof.
Section 1.17Retirement
“Retirement” shall mean the Optionee’s retirement at age 55 or over after having been employed by the Company or a Subsidiary or Parent for at least ten (10) consecutive years.
Section 1.18Secretary
“Secretary” shall mean the Secretary of the Company.
Section 1.19Sponsor IRR
“Sponsor IRR” shall mean an amount equal to a pretax compounded annual internal rate of return of at least 20% on the aggregate amount paid by the Sponsor Group for all of their Shares. For the avoidance of doubt, (a) any calculation of Sponsor IRR will take into account cash dividends or other cash distributions paid on Shares, as well as the value of the Shares if and when they become publicly traded, and (b) Sponsor IRR will not be calculated taking into account the receipt by the Sponsor Group or any of their Affiliates of any management, monitoring, transaction or other fees payable to such parties by the Company or any of its Subsidiaries.
Section 1.20Sponsor Return
“Sponsor Return” shall mean, on any given date, an amount equal to the product of 3.0 (3.5 in respect of Fiscal Years 2016 and 2017) times the aggregate amount paid by the Sponsor Group for all of their Shares. For the avoidance of doubt, (a) any calculation of Sponsor Return will take into account cash dividends or other cash distributions paid on Shares, as well as the value of the Shares if and when they become publicly traded, and (b) Sponsor Return will not be calculated taking into account the receipt by the Sponsor Group or any of their Affiliates of any management, monitoring, transaction or other fees payable to such parties by the Company or any of its Subsidiaries.
Section 1.21Time Option
“Time Option” shall have the meaning given such term in Section 2.1 hereof.
ARTICLE II
GRANT OF OPTIONS
Section 2.1Grant of Options
This Agreement evidences the grant to the Optionee, for good and valuable consideration and in each case on the terms and conditions set forth in this Agreement, of the following:
(a) an option to purchase 1,125,000 Shares, granted to Optionee on October 29, 2009, which shall vest in accordance with the provisions of Section 3.1(a)(i) hereof (the “Time Option”); and
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(b) an option to purchase 375,000 Shares, granted to the Optionee on October 29, 2009, which shall vest in accordance with the provisions of Section 3.1(a)(ii) hereof (the “Performance Option”).
Section 2.2Exercise Price
Subject to Section 2.4, the exercise price of the Shares covered by the Option shall be equal $3.50 per Share (the “Exercise Price”).
Section 2.3No Guarantee of Employment
Nothing in this Agreement or in the Plan shall confer upon the Optionee any right to continued employment by the Company or any Subsidiary or Affiliate or shall interfere with or restrict in any way the rights of the Company and its Subsidiaries or Affiliates, which are hereby expressly reserved, to terminate the employment of the Optionee at any time for any reason whatsoever, with or without Cause, subject to the applicable provisions of, if any, the Optionee’s employment agreement with the Company.
Section 2.4Adjustments to Option
The Option shall be subject to the adjustment provisions of Sections 8 and 9 of the Plan,provided,however, that in the event of the payment of an extraordinary dividend by the Company to its stockholders, then: the Exercise Price of the Option shall be reduced by the amount of the dividend paid, but only to the extent the Committee determines it to be permitted under applicable tax laws and not have adverse tax consequences to the Optionee under Section 409A of the Code; and, if such reduction cannot be fully effected due to such tax laws without adverse tax consequences to the Optionee, then the Company shall pay to the Optionee a cash payment, on a per Share basis, equal to the balance of the amount of the dividend not permitted to be applied to reduce the Exercise Price of the applicable Option as follows: (a) for each Share subject to a vested Option, immediately upon the date of such dividend payment; and (b), for each Share subject to an unvested Option, on the date on which such Option becomes vested and exercisable with respect to such Share.
ARTICLE III
PERIOD OF EXERCISABILITY
Section 3.1Commencement of Exercisability
(a) So long as the Optionee continues to be employed by the Company or any other Service Recipients, the Option shall become exercisable pursuant to the following schedules:
(i)Time Option. The Time Option shall become vested and exercisable with respect to 20% of the Shares subject to the Time Option on each of the first five anniversaries of the Grant Date.
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(ii)Performance Option. The Performance Option shall be eligible to become vested and exercisable as to 20% of the Shares subject to such Option at the end of each of the five Fiscal Years if the Company, on a consolidated basis, achieves its annual EBITDA targets as set forth inSchedule A attached hereto (each, an “EBITDA Target”) for the given Fiscal Year. Notwithstanding the foregoing, in the event that an EBITDA Target is not achieved in a particular Fiscal Year, then that portion of the Performance Option that was eligible to vest but failed to vest due to the Company’s failure to achieve its EBITDA Target shall nevertheless vest and become exercisable at the end of either of the two immediately subsequent Fiscal Yearsif the applicable two- or three-year cumulative EBITDA Target (each, a “Cumulative EBITDA Target”) set forth onSchedule A attached hereto is achieved on a cumulative basis at the end of either of the two immediately subsequent Fiscal Years with respect to a Fiscal Year completed no more than two years prior to the then completed Fiscal Year(s); provided that, in the event that an EBITDA Target is not achieved in either of Fiscal Years 2013 and 2014, then that portion of the Performance Option that was eligible to vest but failed to vest due to the Company’s failure to achieve its EBITDA Target or the applicable Cumulative EBITDA Target shall nevertheless vest and become exercisable at the end of either of the two immediately subsequent Fiscal Years of the Companyif the budgeted EBITDA target set by the Board and the Committee in respect of such Fiscal Year of the Company is achieved and the excess over such budgeted amount is sufficient to satisfy the shortfall from Fiscal Year 2013 or 2014. For purposes of the foregoing proviso clause, the term “Fiscal Year” shall include calendar years 2015 and 2016.
(b) Notwithstanding any of Section 3.1(a) above, upon the occurrence of a termination of employment without Cause, termination of employment on account of the Company or other applicable Service Recipient’s failure to renew the Optionee’s existing employment agreement, or a resignation by the Optionee for Good Reason, in each case following the occurrence of a Change in Control, the Time Option shall become immediately exercisable as to 100% of the Shares subject to such Option immediately prior to the Change of Control.
(c) Notwithstanding any of Section 3.1(a) above, upon the occurrence of a Liquidity Event, subject to the Optionee being employed on the date of such event, the Performance Option shall become immediately exercisable as to 100% of the Shares subject to such Option immediately prior to the Liquidity Event (but only to the extent such Option has not otherwise terminated or become exercisable). If Sponsor IRR and Sponsor Return would not be achieved as a result of the Performance Options becoming immediately exercisable as to 100% of the Shares subject to such Option pursuant to the preceding sentence, “100%” in the preceding sentence shall be replaced with the maximum percentage so that either the Sponsor IRR or Sponsor Return is achieved. In the event that the Sponsor Group receives Marketable Securities in an event constituting a Measurement Date (including, following a public offering, Shares) in excess of more than 25% of the aggregate amount realized in such event, (1) Sponsor IRR and Sponsor Return shall be initially calculated at the time of the Measurement Date without regard to the value of such Marketable Securities so received and such resulting Sponsor Return and Sponsor IRR shall be used to determine vesting of Shares subject to the Performance Option in accordance with this Section 3.1(c); and (2) if the Sponsor Return and/or Sponsor IRR as calculated in (1) above do not result in 100% vesting of the outstanding exercisable Shares subject to such Performance Option immediately prior to the Measurement Date, Sponsor Return and Sponsor IRR shall be recalculated upon each direct or indirect disposition of such Marketable Securities by the Sponsor Group for cash, discounting the cash received to determine its present value at the time of the Measurement Date. If such recalculated Sponsor IRR and/or Sponsor Return would have resulted in 100% vesting of all Shares subject to the Performance Option at the time of the Measurement Date, then 100% of such Performance Option shall immediately vest;provided,however, that any Optionee whose employment is terminated without Cause by the Company or as a result of the Company or other applicable Service Recipient’s failure to renew his employment agreement, or who terminates his employment with Good Reason, such Optionee’s Performance Option, or a portion thereof, having been forfeited or cancelled between the occurrence of the Measurement Date and the subsequent vesting of such Performance Option, in accordance with this Section 3.1(c), shall be entitled to the difference between the price per Share paid on the Measurement Date and the strike price of the Performance Option that was so cancelled or forfeited.
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(d) Except as provided above, no Option shall become exercisable as to any additional Shares following the termination of employment of the Optionee for any reason and any Option, which is unexercisable as of the Optionee’s termination of employment, shall immediately expire without payment therefor.
Section 3.2Expiration of Option
Except as otherwise provided in Section 5 or 6 of the Management Stockholder’s Agreement, the Optionee may not exercise the Option, or any portion thereof, to any extent after the first to occur of the following events:
(a) The tenth anniversary of the applicable Grant Date;
(b) The first anniversary of the date of the Optionee’s termination of employment with the Company and all Service Recipients, if the Optionee’s employment is terminated by reason of death or Disability;
(c) Immediately upon the date of an Optionee’s termination of employment by the Company and all Service Recipients for Cause;
(d) Thirty (30) days after the date of an Optionee’s resignation from employment with the Company and all Service Recipients without Good Reason (except due to death or Disability);
(e) One hundred and eighty (180) days after the date of: (i) an Optionee’s resignation from employment with the Company and all Service Recipients for Good Reason; (ii) an Optionee’s Retirement; or (iii) an Optionee’s termination of employment by the Company and all Service Recipients without Cause (for any reason other than as set forth in Sections 3.2(b) or 3.2(g)), including upon nonrenewal of Optionee’s existing employment agreement by the Company or other applicable Service Recipient, in the event such termination listed in (i), (ii), or (iii) occurs prior to the fifth anniversary of the Closing Date;
(f) The Extended Exercise Date in the event of (i) an Optionee’s resignation from employment with the Company and all Service Recipients for Good Reason; (ii) an Optionee’s Retirement; or (iii) an Optionee’s termination of employment by the Company and all Service Recipients without Cause (for any reason other than as set forth in Sections 3.2(b) or 3.2(g)), including upon nonrenewal of Optionee’s existing employment agreement by the Company or other applicable Service Recipient, and any such termination listed in (i), (ii), or (iii) occurs on or after the fifth anniversary of the Closing Date;
(g) The Extended Exercise Date in the event of an Optionee’s Job Elimination;
(h) Immediately upon the date of an Optionee’s breach of the provisions of Section 22(a)(ii) of the Management Stockholder’s Agreement; or
(i) At the discretion of the Company, if the Committee so determines pursuant to Section 9 of the Plan, but only to the extent the Committee determines it to be permitted under applicable tax laws and not have adverse tax consequences to the Optionee under Section 409A of the Code.
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Notwithstanding the foregoing, the time periods set forth in this Section 3.2 shall not begin to run with respect to Performance Options that vest in accordance with Section 3.1(a)(ii) above until the time at which the Board certifies the financial statements for the Company for the Fiscal Year immediately preceding the Fiscal Year in which, or for the Fiscal Year in which, termination of employment occurs. For purposes of the foregoing provision, the term “Fiscal Year” shall include calendar years 2015 and 2016.
ARTICLE IV
EXERCISE OF OPTION
Section 4.1Person Eligible to Exercise
During the lifetime of the Optionee, only the Optionee (or his duly authorized legal representative) may exercise the Option or any portion thereof. After the death of the Optionee, any exercisable portion of the Option may, prior to the time when an Option becomes unexercisable under Section 3.2, be exercised by his personal representative or by any person empowered to do so under the Optionee’s will or under the then applicable laws of descent and distribution.
Section 4.2Partial Exercise
Any exercisable portion of the Option or the entire Option, if then wholly exercisable, may be exercised in whole or in part at any time prior to the time when the Option or portion thereof becomes unexercisable under Section 3.2;provided,however, that any partial exercise shall be for whole Shares only.
Section 4.3Manner of Exercise
The Option, or any exercisable portion thereof, may be exercised solely by delivering to the Secretary or his office all of the following prior to the time when the Option or such portion becomes unexercisable under Section 3.2:
(a) Notice in writing signed by the Optionee or the other person then entitled to exercise the Option or portion thereof, stating that the Option or portion thereof is thereby exercised, such notice complying with all applicable rules established by the Committee;
(b) (i) Full payment (in cash, by check, or by a combination thereof or through tender of previously owned Shares (any such Shares valued at Fair Market Value on the date of exercise) that the Participant has held for at least six months (or such other period as may be required by the Company’s accountants but only to the extent required to avoid liability accounting under FAS 123(R) or any successor standard thereto)) for the Shares with respect to which such Option or portion thereof is exercised or (ii) indication that the Optionee elects to have the number of Shares that would otherwise be issued to the Optionee reduced by a number of Shares having an equivalent Fair Market Value to the payment that would otherwise be made by the Optionee to the Company pursuant to clause (i) of this subsection (b);
(c) (i) Full payment (in cash or by check or by a combination thereof) to satisfy the minimum withholding tax obligation with respect to which such Option or portion thereof is exercised; or (ii) notice in writing that the Optionee elects to have the number of Shares that would otherwise be issued to the Optionee reduced by a number of Shares having an equivalent Fair Market Value to the payment that would otherwise be made by the Optionee to the Company pursuant to clause (i) of this subsection (c);
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(d) A bona fide written representation and agreement, in a form satisfactory to the Committee, signed by the Optionee or other person then entitled to exercise such Option or portion thereof, stating that the Shares are being acquired for his own account, for investment and without any present intention of distributing or reselling said Shares or any of them except as may be permitted under the Securities Act of 1933, as amended (the “Act”), and then applicable rules and regulations thereunder, and that the Optionee or other person then entitled to exercise such Option or portion thereof will indemnify the Company against and hold it free and harmless from any loss, damage, expense or liability resulting to the Company if any sale or distribution of the Shares by such person is contrary to the representation and agreement referred to above;provided,however, that the Committee may, in its reasonable discretion, take whatever additional actions it deems reasonably necessary to ensure the observance and performance of such representation and agreement and to effect compliance with the Act and any other federal or state securities laws or regulations; and
(e) In the event the Option or portion thereof shall be exercised pursuant to Section 4.1 by any person or persons other than the Optionee, appropriate proof of the right of such person or persons to exercise the Option.
Without limiting the generality of the foregoing, the Committee may require an opinion of counsel acceptable to it to the effect that any subsequent transfer of Shares acquired on exercise of an Option does not violate the Act, and may issue stop-transfer orders covering such Shares. Share certificates evidencing stock issued on exercise of this Option shall bear an appropriate legend referring to the provisions of subsection (d) above and the agreements herein. The written representation and agreement referred to in subsection (d) above shall, however, not be required if the Shares to be issued pursuant to such exercise have been registered under the Act, and such registration is then effective in respect of such Shares.
Section 4.4Conditions to Issuance of Stock Certificates
The Shares of stock deliverable upon the exercise of the Option, or any portion thereof, may be either previously authorized but unissued Shares or issued Shares, which have then been reacquired by the Company. Such Shares shall be fully paid and nonassessable. The Company shall not be required to issue or deliver any certificate or certificates for Shares of stock purchased (if certified, or if not certified, register the issuance of such Shares on its books and records) upon the exercise of the Option or a portion thereof if the issuance of Shares upon exercise would constitute a violation of any applicable federal, state or foreign securities laws or other law or regulations and prior to fulfillment of all of the following conditions:
(a) The obtaining of approval or other clearance from any state or federal governmental agency which the Committee shall, in its reasonable and good faith discretion, determine to be necessary or advisable;
(b) The execution by the Optionee of the Management Stockholder’s Agreement and a Sale Participation Agreement; and
(c) The lapse of such reasonable period of time following the exercise of the Option as the Committee may from time to time establish for reasons of administrative convenience or as may otherwise be required by applicable law.
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The inability of the Company to obtain from any regulatory body having jurisdiction the authority, if any, deemed by the Company’s legal counsel to be necessary to the lawful issuance and sale of any Shares subject to the Option will relieve the Company of any liability in respect of the failure to issue or sell such Shares as to which such requisite authority has not been obtained.
Section 4.5Rights as Stockholder
Except as otherwise provided in Section 2.4 of this Agreement, the holder of an Option shall not be, nor have any of the rights or privileges of, a stockholder of the Company in respect of any Shares purchasable upon the exercise of the Option or any portion thereof unless and until certificates representing such Shares shall have been issued by the Company to such holder or the Shares have otherwise been recorded in the records of the Company as owned by such holder.
ARTICLE V
MISCELLANEOUS
Section 5.1Administration
The Committee shall have the power to adopt, interpret, or revoke rules for the administration, interpretation and application of the Plan. All actions taken and all interpretations and determinations made by the Committee shall be final and binding upon the Optionee, the Company and all other interested persons. No member of the Committee shall be personally liable for any action, determination or interpretation made in good faith with respect to the Plan or the Option. In its absolute discretion, the Board may at any time and from time to time exercise any and all rights and duties of the Committee under the Plan and this Agreement.
Section 5.2Option Not Transferable
Neither the Option nor any interest or right therein or part thereof shall be liable for the debts, contracts or engagements of the Optionee or his successors in interest or shall be subject to disposition by transfer, alienation, anticipation, pledge, encumbrance, assignment or any other means whether such disposition be voluntary or involuntary or by operation of law by judgment, levy, attachment, garnishment or any other legal or equitable proceedings (including bankruptcy), and any attempted disposition thereof shall be null and void and of no effect;provided,however, that this Section 5.2 shall not prevent transfers by will or by the applicable laws of descent and distribution or any transfer permitted in accordance with the terms and conditions of the Management Stockholder’s Agreement or the Sale Participation Agreement.
Section 5.3Notices
Any notice to be given under the terms of this Agreement to the Company shall be addressed to the Company in care of its Secretary, and any notice to be given to the Optionee shall be addressed to him at the last address on file with the Company. By a notice given pursuant to this Section 5.3 either party may hereafter designate a different address for notices to be given to that party. Any notice, which is required to be given to the Optionee, shall, if the Optionee is then deceased, be given to the Optionee’s personal representative if such representative has previously informed the Company of his status and address by written notice under this Section 5.3. Any notice shall have been deemed duly given when (i) delivered in person or (ii) enclosed in a properly addressed, sealed envelope or wrapper, deposited (with postage or fees prepaid) with a post office or branch post office regularly maintained by the United States Postal Service or an office regularly maintained by FedEx, UPS, or comparable non-public mail carrier. Any person entitled to notice hereunder may, by written form, waive such notice.
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Section 5.4Titles; Pronouns
Titles are provided herein for convenience only and are not to serve as a basis for interpretation or construction of this Agreement. The masculine pronoun shall include the feminine and neuter, and the singular the plural, where the context so indicates.
Section 5.5Applicability of Plan, Management Stockholder’s Agreement and Sale Participation Agreement
The Option and the Shares issued to the Optionee upon exercise of the Option shall be subject to all of the terms and provisions of the Plan, the Management Stockholder’s Agreement and a Sale Participation Agreement, to the extent applicable to the Option and such Shares. In the event of any conflict or inconsistency between the terms hereof and the terms of the Plan, the terms of the Plan shall be controlling.
Section 5.6Amendment
Subject to Section 10 of the Plan, this Agreement may be amended only by a writing executed by the parties hereto, which specifically states that it is amending this Agreement.
Section 5.7Governing Law
The laws of the State of Texas shall govern the interpretation, validity and performance of the terms of this Agreement regardless of the law that might be applied under principles of conflicts of laws.
Section 5.8Arbitration
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 within the Dallas, Texas metropolitan area. 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. Each party shall bear its own legal fees and expenses, unless otherwise determined by the arbitrator.
Section 5.9Furnish Information
Optionee agrees to furnish to the Company all information requested by the Company to enable it to comply with any reporting or other requirement imposed upon the Company by or under any applicable statute or regulation.
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Section 5.10Remedies
The Company shall be entitled to recover from Optionee reasonable attorneys’ fees incurred in connection with the enforcement of the terms and provisions of this Agreement whether by an action to enforce specific performance or for damages for its breach or otherwise.
Section 5.11No Liability for Good Faith Determinations
The Company and the members of the Committee and the Board shall not be liable for any act, omission or determination taken or made in good faith with respect to this Agreement or the Option granted hereunder.
Section 5.12Execution of Receipts and Releases
Any payment of cash or any issuance or transfer of Shares or other property to Optionee, or to Optionee’s legal representative, heir, legatee or distributee, in accordance with the provisions hereof, shall, to the extent thereof, be in full satisfaction of all claims of such persons hereunder. The Company may require Optionee or Optionee’s legal representative, heir, legatee or distributee, as a condition precedent to such payment or issuance, to execute a release and receipt therefore in such form as it shall determine.
Section 5.13No Guarantee of Interests
The Board and the Company do not guarantee the Common Stock of the Company from loss or depreciation.
Section 5.14Company Records
Records of the Company regarding Optionee’s service and other matters shall be conclusive for all purposes hereunder, unless determined by the Company to be incorrect.
Section 5.15Information Confidential
As partial consideration for the granting of this Option, Optionee agree that Optionee will keep confidential all information and knowledge that Optionee has relating to the manner and amount of his participation in the Plan; provided, however, that such information may be disclosed as required by law and may be given in confidence to Optionee’s spouse, tax and financial advisors. In the event any breach of this promise comes to the attention of the Company, it shall take into consideration that breach in determining whether to recommend the grant of any future similar award to Optionee, as a factor weighing against the advisability of granting any such future award.
Section 5.16Successors
This Agreement shall be binding upon Optionee, Optionee’s legal representatives, heirs, legatees and distributees, and upon the Company, its successors and assigns.
Section 5.17Severability
If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid provision had never been included herein.
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Section 5.18Company Action
Any action required of the Company shall be by resolution of the Board or by a person authorized to act by resolution of the Board.
Section 5.19Word Usage
Words used in the masculine shall apply to the feminine where applicable, and wherever the context of this Agreement dictates, the plural shall be read as the singular and the singular as the plural.
Section 5.20No Assignment
Optionee may not assign this Agreement or any of Optionee’s rights under this Agreement without the Company’s prior written consent, and any purported or attempted assignment without such prior written consent shall be void.
[Signatures on next page.]
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IN WITNESS WHEREOF, this Agreement has been executed and delivered by the parties hereto.
| ENERGY FUTURE HOLDINGS CORP. | ||
| By: | /s/ Robert C. Walters | |
| Name: | Robert C. Walters | |
| Its: | Executive Vice President and General Counsel | |
| OPTIONEE: | ||
| By: | /s/ Joel Kaplan | |
Summary of Option grants governed by this Agreement appears on the following page.
[Signature Page of Stock Option Agreement]
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Summary of Option
| Time Option | Performance Option | |||||
Aggregate number of Shares subject to the Option | 1,125,000 | 375,000 | ||||
Grant Date | October 29, 2009 | October 29, 2009 | ||||
Exercise Price | $ | 3.50 | $ | 3.50 | ||
[Summary of Option Grants]
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Exhibit 10(gg)
ENERGY FUTURE HOLDINGS CORP. KEY EMPLOYEE
NON-QUALIFIED STOCK OPTION AGREEMENT
RICHARD LANDY
THIS AGREEMENT (“Agreement”), dated as of January 26, 2010 (the “Effective Date”), is made by and between Energy Future Holdings Corp., a Texas corporation (hereinafter referred to as the “Company”), and the individual whose name is set forth on the signature page hereof (hereinafter referred to as the “Optionee”). Any capitalized terms used but not otherwise defined herein shall have the meaning set forth in the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates (the “Plan”).
WHEREAS, the Company wishes to act consistently with the Plan, the terms of which are incorporated by reference and made part of this Agreement; and
WHEREAS, the Organization and Compensation Committee of the Board of the Company (the “Committee”) has determined that it would be to the advantage and best interest of the Company and its shareholders to grant the Option provided for herein to the Optionee as an incentive for increased efforts during his term of employment with the Company or its Subsidiaries or Affiliates, and has advised the Company thereof and authorized the undersigned officers to issue said Option.
NOW, THEREFORE, in consideration of the mutual covenants herein contained and other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereto do hereby agree as follows:
ARTICLE I
DEFINITIONS
Whenever the following terms are used in this Agreement, they shall have the meaning specified below unless the context clearly indicates to the contrary.
Section 1.1Cause
“Cause” shall mean “Cause” as defined in the employment agreement or change-in-control agreement between the Optionee and the Company or any of its Subsidiaries or Affiliates, or, if there is no such employment or change-in-control agreement in effect at the time Optionee’s employment is terminated, “Cause” shall mean, with respect to an Optionee: (i) if, in carrying out his duties to the Company, the Optionee engages in conduct that constitutes (a) a material breach of his fiduciary duty to the Company or its shareholders (including, without limitation a material breach or attempted breach of the restrictive covenants under the Management Stockholder’s Agreement), (b) gross neglect or (c) gross misconduct resulting in material economic harm to the Company, provided that any such conduct described in (a), (b) or (c) is not cured within ten (10) business days after the Optionee receives from the Company written notice thereof, or (ii) Optionee’s conviction of, or entry of a plea of guilty or nolo contendere for, a felony or other crime involving moral turpitude.
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Section 1.2Deemed Retirement
“Deemed Retirement” shall mean the Optionee’s termination of employment for any reason after having been employed by the Company or a Subsidiary or Parent for at least three (3) consecutive years. For the avoidance of doubt, the Optionee’s retirement at age 55 or over after having been employed by the Company or a Subsidiary or Parent for at least ten (10) consecutive years shall constitute “Retirement” not a “Deemed Retirement” for purposes of this Agreement.
Section 1.3Disability
“Disability” shall mean “Disability” as defined in the employment agreement between the Optionee and the Company or any of its Subsidiaries, or, if there is no such employment agreement, “Disability” shall mean the Optionee’s physical or mental incapacitation and consequent inability for a period of six consecutive months to perform the Optionee’s duties;provided,however, in the event the Company temporarily replaces the Optionee, or transfers the Optionee’s duties or responsibilities to another individual, on account of the Optionee’s mental or physical impairment for a period of time which is covered by the Company’s short term disability plan, the Optionee’s employment shall not be deemed terminated by the Company and the Optionee shall not be able to resign with Good Reason.
Section 1.4Extended Exercise Date
“Extended Exercise Date” shall mean the earlier of: (i) the tenth anniversary of the Grant Date; or (ii) the later of the date: (A) one hundred and eighty (180) days following the date Optionee’s employment with the Company and all Service Recipients is terminated and (B) thirty (30) days following the first date on which the Optionee could exercise the Option, or any portion thereof, and immediately resell the Shares acquired upon such exercise for cash consideration.
Section 1.5Fair Market Value
“Fair Market Value” shall mean, for the purposes of the Plan and this Agreement and notwithstanding the definition contained in the Plan: (i) if there is a public market for the Shares on such date, the average of the high and low closing bid prices of the Shares on such stock exchange on which the Shares are principally trading on the date in question, or, if there were no sales on such date, on the closest preceding date on which there were sales of Shares or, (ii) if there is no public market for the Shares, on a per Share basis, the fair market value of the Shares on any given date, as determined reasonably and in good faith by the Board, which shall not take into account any minority interest discount or a discount for illiquidity of Shares held by an Optionee in excess of any illiquidity discount applicable to Shares generally; provided that if the Board’s determination under this clause (ii) is not based on a valuation completed by an independent valuation firm within the 6 months preceding the Board’s determination, the Optionee may require the Company to retain an independent valuation firm to determine the fair market value (and the Company will bear the cost of such appraisal, unless the appraised value is 110% or less of the fair market value as determined by the Board, in which case the Optionee will bear the cost of such appraisal).
Section 1.6Good Reason
“Good Reason” shall mean “Good Reason” as defined in the employment agreement or change-in-control agreement between the Optionee and the Company or any of its Subsidiaries or Affiliates, or, if there is no such employment or change-in-control agreement in effect at the time Optionee’s employment is terminated, “Good Reason” shall mean (i) a reduction in the Optionee’s base salary or the Optionee’s annual incentive compensation opportunity (other than a general reduction in base salary or annual incentive compensation opportunity that affects all salaried employees of the Company proportionately); (ii) a transfer of the Optionee’s primary workplace by more than thirty-five (35) miles from the current workplace; (iii) a substantial adverse change in the Optionee’s duties and responsibilities; (iv) any material breach by the Company of this Agreement, the Management Stockholder’s Agreement, or the Optionee’s employment agreement; or (v) an adverse change in the Optionee’s line of reporting to superior officers pursuant to the terms of his employment agreement or any change-in-control agreement;provided,however, that any isolated, insubstantial and inadvertent failure by the Company that is not in bad faith and is cured within ten (10) business days after the Optionee gives the Company written notice of any such event set forth above, shall not constitute Good Reason.
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Section 1.7Grant Date
“Grant Date” means the date the Option is granted, which is specified in Section 2.1 hereof.
Section 1.8Job Elimination
“Job Elimination” shall mean the termination of an Optionee’s employment without Cause by the Company or any of its Subsidiaries or Affiliates in either of fiscal year 2011 or 2012 due to the elimination of the Optionee’s job position, to the extent determined by the Chief Executive Officer and approved by the Committee that such elimination occurred.
Section 1.9Management Stockholder’s Agreement
“Management Stockholder’s Agreement” shall mean the Management Stockholder’s Agreement between the Optionee and the Company.
Section 1.10Option
“Option” shall have the meaning given such term in Section 2.1 hereof.
Section 1.11Parent
“Parent” shall mean Texas Energy Future Holdings Limited Partnership, a Delaware Limited Partnership.
Section 1.12Retirement
“Retirement” shall mean the Optionee’s retirement at age 55 or over after having been employed by the Company or a Subsidiary or Parent for at least ten (10) consecutive years.
Section 1.13Secretary
“Secretary” shall mean the Secretary of the Company.
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ARTICLE II
GRANT OF OPTIONS
Section 2.1Grant of Options
This Agreement evidences the grant to the Optionee, for good and valuable consideration and on the terms and conditions set forth in this Agreement, of an option to purchase 400,000 Shares, granted to Optionee on December 31, 2009, which shall vest in accordance with the provisions of Section 3.1 hereof (the “Option”).
Section 2.2Exercise Price
Subject to Section 2.4, the exercise price of the Shares covered by the Option shall be equal to $3.50 per Share (the “Exercise Price”).
Section 2.3No Guarantee of Employment
Nothing in this Agreement or in the Plan shall confer upon the Optionee any right to continued employment by the Company or any Subsidiary or Affiliate or shall interfere with or restrict in any way the rights of the Company and its Subsidiaries or Affiliates, which are hereby expressly reserved, to terminate the employment of the Optionee at any time for any reason whatsoever, with or without Cause, subject to the applicable provisions of, if any, the Optionee’s employment agreement with the Company.
Section 2.4Adjustments to Option
The Option shall be subject to the adjustment provisions of Sections 8 and 9 of the Plan,provided,however, that in the event of the payment of an extraordinary dividend by the Company to its stockholders, then: the Exercise Price of the Option shall be reduced by the amount of the dividend paid, but only to the extent the Committee determines it to be permitted under applicable tax laws and not to have adverse tax consequences to the Optionee under Section 409A of the Code; and, if such reduction cannot be fully effected due to such tax laws without adverse tax consequences to the Optionee, then the Company shall pay to the Optionee a cash payment, on a per Share basis, equal to the balance of the amount of the dividend not permitted to be applied to reduce the Exercise Price of the applicable Option as follows: (a) for each Share subject to a vested Option, immediately upon the date of such dividend payment; and (b) for each Share subject to an unvested Option, on the date on which such Option becomes vested and exercisable with respect to such Share.
ARTICLE III
PERIOD OF EXERCISABILITY
Section 3.1Commencement of Exercisability
(a) The Option shall become vested and exercisable in accordance with the following schedule, provided the Optionee has remained continuously employed by the Company or any other Service Recipients through the applicable vesting dates:
Vesting Date | Cumulative Percentage of Shares Subject to the Option that are Vested and Exercisable | |
| July 4, 2011 | 50% | |
| January 4, 2013 | 50% | |
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(b) Notwithstanding any of Section 3.1(a) above, upon the occurrence of a termination of employment without Cause, termination of employment on account of the Company or other applicable Service Recipient’s failure to renew the Optionee’s existing employment agreement, or a resignation by the Optionee for Good Reason, in each case following the occurrence of a Change in Control, the Option shall become immediately exercisable as to 100% of the Shares subject to such Option immediately prior to the Change in Control.
(c) Except as provided above, no Option shall become exercisable as to any additional Shares following the termination of employment of the Optionee for any reason and any Option, which is unexercisable as of the Optionee’s termination of employment, shall immediately expire without payment therefor.
Section 3.2Expiration of Option
Except as otherwise provided in Section 5 or 6 of the Management Stockholder’s Agreement, the Optionee may not exercise the Option, or any portion thereof, to any extent after the first to occur of the following events:
(a) The tenth anniversary of the Grant Date;
(b) The first anniversary of the date of the Optionee’s termination of employment with the Company and all Service Recipients, if the Optionee’s employment is terminated by reason of death, Disability, or Deemed Retirement;
(c) Immediately upon the date of an Optionee’s termination of employment by the Company and all Service Recipients for Cause;
(d) Thirty (30) days after the date of an Optionee’s resignation from employment with the Company and all Service Recipients without Good Reason (except due to death, Disability, or Deemed Retirement);
(e) One hundred and eighty (180) days after the date of: (i) an Optionee’s resignation from employment with the Company and all Service Recipients for Good Reason; or (ii) an Optionee’s Retirement; or (iii) an Optionee’s termination of employment by the Company and all Service Recipients without Cause (for any reason other than death, Disability, Job Elimination, or Deemed Retirement), including upon nonrenewal of Optionee’s existing employment agreement by the Company or other applicable Service Recipient, in the event such termination listed in (i), (ii), or (iii) occurs prior to the fifth anniversary of October 10, 2007;
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(f) The Extended Exercise Date in the event of (i) an Optionee’s resignation from employment with the Company and all Service Recipients for Good Reason; (ii) an Optionee’s Retirement; or (iii) an Optionee’s termination of employment by the Company and all Service Recipients without Cause (for any reason other than death, Disability, Job Elimination, or Deemed Retirement), including upon nonrenewal of Optionee’s existing employment agreement by the Company or other applicable Service Recipient, and any such termination listed in (i), (ii), or (iii) occurs on or after the fifth anniversary of October 10, 2007;
(g) The Extended Exercise Date in the event of an Optionee’s Job Elimination;
(h) Immediately upon the date of an Optionee’s breach of the provisions of Section 22(a)(ii) of the Management Stockholder’s Agreement; or
(i) At the discretion of the Company, if the Committee so determines pursuant to Section 9 of the Plan, but only to the extent the Committee determines it to be permitted under applicable tax laws and to not have adverse tax consequences to the Optionee under Section 409A of the Code.
ARTICLE IV
EXERCISE OF OPTION
Section 4.1Person Eligible to Exercise
During the lifetime of the Optionee, only the Optionee (or his duly authorized legal representative) may exercise the Option or any portion thereof. After the death of the Optionee, any exercisable portion of the Option may, prior to the time when an Option becomes unexercisable under Section 3.2, be exercised by his personal representative or by any person empowered to do so under the Optionee’s will or under the then applicable laws of descent and distribution.
Section 4.2Partial Exercise
Any exercisable portion of the Option or the entire Option, if then wholly exercisable, may be exercised in whole or in part at any time prior to the time when the Option or portion thereof becomes unexercisable under Section 3.2;provided,however, that any partial exercise shall be for whole Shares only.
Section 4.3Manner of Exercise
The Option, or any exercisable portion thereof, may be exercised solely by delivering to the Secretary or her office all of the following prior to the time when the Option or such portion becomes unexercisable under Section 3.2:
(a) Notice in writing signed by the Optionee or the other person then entitled to exercise the Option or portion thereof, stating that the Option or portion thereof is thereby exercised, such notice complying with all applicable rules established by the Committee;
(b) (i) Full payment (in cash, by check, or by a combination thereof or through tender of previously owned Shares (any such Shares valued at Fair Market Value on the date of exercise) that the Participant has held for at least six months (or such other period as may be required by the Company’s accountants but only to the extent required to avoid liability accounting under FAS 123(R) or any successor standard thereto)) for the Shares with respect to which such Option or portion thereof is exercised or (ii) indication that the Optionee elects to have the number of Shares that would otherwise be issued to the Optionee reduced by a number of Shares having an equivalent Fair Market Value to the payment that would otherwise be made by the Optionee to the Company pursuant to clause (i) of this subsection (b);
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(c) (i) Full payment (in cash or by check or by a combination thereof) to satisfy the minimum withholding tax obligation with respect to which such Option or portion thereof is exercised; or (ii) notice in writing that the Optionee elects to have the number of Shares that would otherwise be issued to the Optionee reduced by a number of Shares having an equivalent Fair Market Value to the payment that would otherwise be made by the Optionee to the Company pursuant to clause (i) of this subsection (c);
(d) A bona fide written representation and agreement, in a form satisfactory to the Committee, signed by the Optionee or other person then entitled to exercise such Option or portion thereof, stating that the Shares are being acquired for his own account, for investment and without any present intention of distributing or reselling said Shares or any of them except as may be permitted under the Securities Act of 1933, as amended (the “Act”), and then applicable rules and regulations thereunder, and that the Optionee or other person then entitled to exercise such Option or portion thereof will indemnify the Company against and hold it free and harmless from any loss, damage, expense or liability resulting to the Company if any sale or distribution of the Shares by such person is contrary to the representation and agreement referred to above;provided,however, that the Committee may, in its reasonable discretion, take whatever additional actions it deems reasonably necessary to ensure the observance and performance of such representation and agreement and to effect compliance with the Act and any other federal or state securities laws or regulations; and
(e) In the event the Option or portion thereof shall be exercised pursuant to Section 4.1 by any person or persons other than the Optionee, appropriate proof of the right of such person or persons to exercise the Option.
Without limiting the generality of the foregoing, the Committee may require an opinion of counsel acceptable to it to the effect that any subsequent transfer of Shares acquired on exercise of an Option does not violate the Act, and may issue stop-transfer orders covering such Shares. Share certificates evidencing stock issued on exercise of this Option shall bear an appropriate legend referring to the provisions of subsection (d) above and the agreements herein. The written representation and agreement referred to in subsection (d) above shall, however, not be required if the Shares to be issued pursuant to such exercise have been registered under the Act, and such registration is then effective in respect of such Shares.
Section 4.4Conditions to Issuance of Stock Certificates
The Shares deliverable upon the exercise of the Option, or any portion thereof, may be either previously authorized but unissued Shares or issued Shares, which have then been reacquired by the Company. Such Shares shall be fully paid and nonassessable. The Company shall not be required to issue or deliver any certificate or certificates for Shares of stock purchased (if certified, or if not certified, register the issuance of such Shares on its books and records) upon the exercise of the Option or a portion thereof if the issuance of Shares upon exercise would constitute a violation of any applicable federal, state or foreign securities laws or other law or regulations and prior to fulfillment of all of the following conditions:
(a) The obtaining of approval or other clearance from any state or federal governmental agency which the Committee shall, in its reasonable and good faith discretion, determine to be necessary or advisable;
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(b) The execution by the Optionee of the Management Stockholder’s Agreement and a Sale Participation Agreement; and
(c) The lapse of such reasonable period of time following the exercise of the Option as the Committee may from time to time establish for reasons of administrative convenience or as may otherwise be required by applicable law.
The inability of the Company to obtain from any regulatory body having jurisdiction the authority, if any, deemed by the Company’s legal counsel to be necessary to the lawful issuance and sale of any Shares subject to the Option will relieve the Company of any liability in respect of the failure to issue or sell such Shares as to which such requisite authority has not been obtained.
Section 4.5Rights as Stockholder
Except as otherwise provided in Section 2.4 of this Agreement, the holder of an Option shall not be, nor have any of the rights or privileges of, a stockholder of the Company with respect to any Shares purchasable upon the exercise of the Option or any portion thereof unless and until certificates representing such Shares shall have been issued by the Company to such holder or the Shares have otherwise been recorded in the records of the Company as owned by such holder.
ARTICLE V
MISCELLANEOUS
Section 5.1Administration
The Committee shall have the power to adopt, interpret, or revoke rules for the administration, interpretation and application of the Plan. All actions taken and all interpretations and determinations made by the Committee shall be final and binding upon the Optionee, the Company and all other interested persons. No member of the Committee shall be personally liable for any action, determination or interpretation made in good faith with respect to the Plan or the Option. In its absolute discretion, the Board may at any time and from time to time exercise any and all rights and duties of the Committee under the Plan and this Agreement.
Section 5.2Option Not Transferable
Neither the Option nor any interest or right therein or part thereof shall be liable for the debts, contracts or engagements of the Optionee or his successors in interest or shall be subject to disposition by transfer, alienation, anticipation, pledge, encumbrance, assignment or any other means whether such disposition be voluntary or involuntary or by operation of law by judgment, levy, attachment, garnishment or any other legal or equitable proceedings (including bankruptcy), and any attempted disposition thereof shall be null and void and of no effect;provided,however, that this Section 5.2 shall not prevent transfers by will or by the applicable laws of descent and distribution or any transfer permitted in accordance with the terms and conditions of the Management Stockholder’s Agreement or the Sale Participation Agreement.
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Section 5.3Notices
Any notice to be given under the terms of this Agreement to the Company shall be addressed to the Company in care of its Secretary, and any notice to be given to the Optionee shall be addressed to him at the last address on file with the Company. By a notice given pursuant to this Section 5.3 either party may hereafter designate a different address for notices to be given to that party. Any notice, which is required to be given to the Optionee, shall, if the Optionee is then deceased, be given to the Optionee’s personal representative if such representative has previously informed the Company of his status and address by written notice under this Section 5.3. Any notice shall have been deemed duly given when (i) delivered in person or (ii) enclosed in a properly addressed, sealed envelope or wrapper, deposited (with postage or fees prepaid) with a post office or branch post office regularly maintained by the United States Postal Service or an office regularly maintained by FedEx, UPS, or comparable non-public mail carrier. Any person entitled to notice hereunder may, by written form, waive such notice.
Section 5.4Titles
Titles are provided herein for convenience only and are not to serve as a basis for interpretation or construction of this Agreement.
Section 5.5Applicability of Plan, Management Stockholder’s Agreement and Sale Participation Agreement
The Option and the Shares issued to the Optionee upon exercise of the Option shall be subject to all of the terms and provisions of the Plan, the Management Stockholder’s Agreement and a Sale Participation Agreement, to the extent applicable to the Option and such Shares. In the event of any conflict or inconsistency between the terms hereof and the terms of the Plan, the terms of the Plan shall be controlling.
Section 5.6Amendment
Subject to Section 10 of the Plan, this Agreement may be amended only by a writing executed by the parties hereto, which specifically states that it is amending this Agreement.
Section 5.7Governing Law
The laws of the State of Texas shall govern the interpretation, validity and performance of the terms of this Agreement regardless of the law that might be applied under principles of conflicts of laws.
Section 5.8Arbitration
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 within the Dallas, Texas metropolitan area. 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. Each party shall bear its own legal fees and expenses, unless otherwise determined by the arbitrator.
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Section 5.9Furnish Information
Optionee agrees to furnish to the Company all information requested by the Company to enable it to comply with any reporting or other requirement imposed upon the Company by or under any applicable statute or regulation.
Section 5.10Remedies
The Company shall be entitled to recover from Optionee reasonable attorneys’ fees incurred in connection with the enforcement of the terms and provisions of this Agreement whether by an action to enforce specific performance or for damages for its breach or otherwise.
Section 5.11No Liability for Good Faith Determinations
The Company and the members of the Committee and the Board shall not be liable for any act, omission or determination taken or made in good faith with respect to this Agreement or the Option granted hereunder.
Section 5.12Execution of Receipts and Releases
Any payment of cash or any issuance or transfer of Shares or other property to Optionee, or to Optionee’s legal representative, heir, legatee or distributee, in accordance with the provisions hereof, shall, to the extent thereof, be in full satisfaction of all claims of such persons hereunder. The Company may require Optionee or Optionee’s legal representative, heir, legatee or distributee, as a condition precedent to such payment or issuance, to execute a release and receipt therefore in such form as it shall determine.
Section 5.13No Guarantee of Interests
The Board and the Company do not guarantee the Common Stock of the Company from loss or depreciation.
Section 5.14Company Records
Records of the Company regarding Optionee’s service and other matters shall be conclusive for all purposes hereunder, unless determined by the Company to be incorrect.
Section 5.15Information Confidential
As partial consideration for the granting of this Option, Optionee agrees that Optionee will keep confidential all information and knowledge that Optionee has relating to the manner and amount of his participation in the Plan; provided, however, that such information may be disclosed as required by law and may be given in confidence to Optionee’s spouse, tax and financial advisors. In the event any breach of this promise comes to the attention of the Company, it shall take into consideration that breach in determining whether to recommend the grant of any future similar award to Optionee, as a factor weighing against the advisability of granting any such future award.
Section 5.16Successors
This Agreement shall be binding upon Optionee, Optionee’s legal representatives, heirs, legatees and distributees, and upon the Company, its successors and assigns.
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Section 5.17Severability
If any provision of this Agreement is held to be illegal or invalid for any reason, the illegality or invalidity shall not affect the remaining provisions hereof, but such provision shall be fully severable and this Agreement shall be construed and enforced as if the illegal or invalid provision had never been included herein.
Section 5.18Word Usage
Words used in the masculine shall apply to the feminine where applicable, and wherever the context of this Agreement dictates, the plural shall be read as the singular and the singular as the plural.
Section 5.19No Assignment
Optionee may not assign this Agreement or any of Optionee’s rights under this Agreement without the Company’s prior written consent, and any purported or attempted assignment without such prior written consent shall be void.
[Signatures on next page.]
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IN WITNESS WHEREOF, this Agreement has been executed and delivered by the parties hereto.
| ENERGY FUTURE HOLDINGS CORP. | ||||
| By: | /s/ Robert C. Walters | |||
| Name: | Robert C. Walters | |||
| Its: | Executive Vice President and General Counsel | |||
OPTIONEE: | ||||
/s/ Richard Landy |
Richard Landy |
Summary of Option grants governed by this Agreement appears on the following page.
[Signature Page of Stock Option Agreement]
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Summary of Option
| Option | |||
Aggregate number of Shares subject to the Option | 400,000 | ||
Grant Date | December 31, 2009 | ||
Exercise Price | $ | 3.50 | |
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Exhibit 10(hh)
RESTRICTED STOCK UNITS AWARD AGREEMENT
THIS AGREEMENT (the “Agreement”) is made effective as of January 6, 2008 (the “Grant Date”), between Energy Future Holdings Corp., a Texas corporation (hereinafter referred to as the “Company”), and John Young, an employee of the Company, hereinafter referred to as the “Grantee.” Capitalized terms not otherwise defined herein shall have the same meanings as in the Plan or the Management Stockholder’s Agreement (each as defined below).
WHEREAS, pursuant to the Employment Agreement entered into between Grantee and the Company of even date herewith (“Employment Agreement”), the Company desires to grant the Grantee shares of Common Stock, pursuant to the terms and conditions of this Agreement (the “Restricted Stock Units Award”), the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates (the “Plan”) (the terms of which are hereby incorporated by reference and made a part of this Agreement), and a Management Stockholder’s Agreement entered into by and between the Company and the Grantee as of the date hereof (the “Management Stockholder’s Agreement”).
WHEREAS, the Committee has determined that it would be to the advantage and best interest of the Company and its shareholders to grant the Restricted Stock Unit Award provided for herein to the Grantee as an incentive for increased efforts during his or her employment with the Company or an Affiliate of the Company, and has advised the Company thereof and instructed the undersigned officer to grant said Restricted Stock Unit Award.
NOW, THEREFORE, in consideration of the mutual covenants herein contained and other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereto do hereby agree as follows:
1.Grant of the Restricted Stock Units. Subject to the terms and conditions of the Plan, the Management Stockholder’s Agreement, and the additional terms and conditions set forth in this Agreement, the Company hereby grants to the Grantee 600,000 Restricted Stock Units. A “Restricted Stock Unit” represents the right to receive one share of Common Stock. The Restricted Stock Units shall vest and become nonforfeitable in accordance with Section 2 hereof.
2.Vesting. All Restricted Stock Units shall be vested and nonforfeitable as to 100% of such shares upon the Grant Date; provided, however, in the event the Grantee voluntarily terminates his employment with the Company without Good Reason (and not due to his Disability) prior to the second anniversary of the Grant Date, the Grantee shall forfeit all of the Restricted Stock Units.
3.Entitlement to Receive Common Stock. Unless otherwise set forth herein or in the Management Stockholder’s Agreement, the Grantee shall be entitled to receive one share of Common Stock for each Restricted Stock Unit that the Grantee holds (and has not forfeited) (such date of delivery, the “Maturity Date”), and delivery of Common Stock hereunder shall be made on the second anniversary of the Grant Date.
4.Rights as a Stockholder. The Grantee shall not have any rights of a common stockholder of the Company unless and until the Grantee becomes entitled to receive the shares of Common Stock pursuant to Section 3 above; provided, the Grantee shall be entitled to receipt of all dividends paid on shares of Common Stock in respect of the Restricted Stock Units, which dividends shall be paid to the Grantee in cash (or Common Stock or such other property as is paid as a dividend to other holders of Common Stock) as and when dividends are paid to other holders of Common Stock. As soon as practicable following the date that the Grantee becomes entitled to receive the shares of Common Stock pursuant to Section 3, the Company shall register the Grantee’s ownership of the Common Stock in the Company’s stock ledger.
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5.Legend on Certificates. The ledger entries for the Common Stock, and any certificates representing the Common Stock, delivered to the Grantee as contemplated by Section 3 above shall bear the legend set forth in Section 2 of the Management Stockholder’s Agreement (which legend shall also be revised to make reference to this Agreement) and shall be subject to such stop transfer orders and other restrictions as the Committee may deem advisable under the Plan or the rules, regulations, and other requirements of the Securities and Exchange Commission or any stock exchange upon which such Common Stock is listed, and any applicable Federal or state laws, and the Committee may cause a legend or legends to be put on any such certificates to make appropriate reference to such restrictions.
6.Transferability. The Restricted Stock Units shall not be subject to alienation, garnishment, execution or levy of any kind, and any attempt to cause any such awards to be so subjected shall not be recognized. The shares of Common Stock acquired by the Grantee pursuant to Section 3 of this Agreement may not at any time be transferred, sold, assigned, pledged, hypothecated or otherwise disposed of unless such transfer, sale, assignment, pledge, hypothecation or other disposition complies with the provisions of the Management Stockholder’s Agreement.
7.Grantee’s Employment by the Company. Nothing contained in this Agreement or in any other agreement entered into by the Company or any of its Subsidiaries and the Grantee, other than the applicable provisions of any employment agreement entered into by and between the Grantee and the Company or any of its Subsidiaries, as applicable, (i) obligates the Company or any Subsidiary to employ the Grantee in any capacity whatsoever or (ii) prohibits or restricts the Company or any Subsidiary from terminating the employment, if any, of the Grantee at any time or for any reason whatsoever, with or without cause, and the Grantee hereby acknowledges and agrees that neither the Company nor any other Person has made any representations or promises whatsoever to the Grantee concerning the Grantee’s employment or continued employment by the Company or any affiliate thereof.
8.Change in Capitalization. If the Company shall be reorganized, or consolidated or merged with another corporation after the Grant Date specified above but prior to the Maturity Date, the number and kind of shares of Common Stock which may be issued with respect to the Restricted Stock Units may or may not be adjusted so as to reflect such change, all as determined by the Committee in its sole discretion.
9.Withholding. It shall be a condition of the obligation of the Company upon delivery of Common Stock to the Grantee pursuant to Section 3 above that the Grantee pay to the Company such amount as may be requested by the Company for the purpose of satisfying any liability for any federal, state or local income or other taxes required by law to be withheld with respect to such Common Stock. The Company shall be authorized to take such action as may be necessary, in the opinion of the Company’s counsel (including, without limitation, withholding Common Stock otherwise deliverable to the Grantee hereunder and/or withholding amounts from any compensation or other amount owing from the Company to the Grantee), to satisfy the obligations for payment of the minimum amount of any such taxes. Notwithstanding the foregoing provisions of this Section 9, the Grantee shall, at his election, be permitted to elect to use Common Stock otherwise deliverable to the Grantee hereunder, having an equivalent Fair Market Value to the payment that would otherwise be made by Grantee to the Company pursuant to the foregoing provisions of this Section 9, to satisfy any such obligations. For such purpose “Fair Market Value” shall have the meaning of such term as defined in the Management Stockholder’s Agreement between the Grantee and the Company. The Grantee is hereby advised to seek his own tax counsel regarding the taxation of the grant of Restricted Stock Units made hereunder.
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10.Limitation on Obligations. The Company’s obligation with respect to the Restricted Stock Units granted hereunder is limited solely to the delivery to the Grantee of shares of Common Stock on the date when such shares are due to be delivered hereunder, and in no way shall the Company become obligated to pay cash in respect of such obligation. This Restricted Stock Unit Award shall not be secured by any specific assets of the Company or any of its Subsidiaries, nor shall any assets of the Company or any of its Subsidiaries be designated as attributable or allocated to the satisfaction of the Company’s obligations under this Agreement. In addition, the Company shall not be liable to the Grantee for damages relating to any delays in issuing the share certificates to him (or his designated entities), any loss of the certificates, or any mistakes or errors in the issuance of the certificates or in the certificates themselves.
11.Securities Laws. Upon the delivery of any Common Stock, the Company may require the Grantee to make or enter into such written representations, warranties and agreements as the Committee may reasonably request in order to comply with applicable securities laws or with this Agreement, consistent with the terms of the Management Stockholder’s Agreement. The delivery of the Common Stock hereunder shall be subject to all applicable laws, rules and regulations and to such approvals of any governmental agencies as may be required.
12.Notices. Any notice to be given under the terms of this Agreement to the Company shall be addressed to the Company in care of its Corporate Secretary, and any notice to be given to the Grantee shall be addressed to him at the address given beneath his signature hereto. By a notice given pursuant to this Section 12, either party may hereafter designate a different address for notices to be given to him. Any notice that is required to be given to the Grantee shall, if the Grantee is then deceased, be given to the Grantee’s personal representative if such representative has previously informed the Company of his status and address by written notice under this Section 12. Any notice shall have been deemed duly given when enclosed in a properly sealed envelope or wrapper addressed as aforesaid and deposited (with postage prepaid) in a post office or branch post office regularly maintained by the United States Postal Service.
13.Governing Law. The laws of the State of Texas shall govern the interpretation, validity and performance of the terms of this Agreement regardless of the law that might be applied under principles of conflicts of laws.
14.Restricted Stock Unit Award Subject to Plan and Other Management Equity Agreements. The Restricted Stock Unit Award shall be subject to all terms and provisions of the Plan, the Management Stockholder’s Agreement and the Sale Participation Agreement, to the extent applicable to the Common Stock. In the event of any conflict between this Agreement and the Plan, the terms of the Plan shall control; provided, however, for purposes of Section 3.1(c) of the Plan, all actions taken and all interpretations and determinations made by the Committee shall be final and binding upon the Grantee, the Company and all other interested persons unless such action, interpretation or determination by the Company was not reasonable, not made in good faith or inconsistent with substantially similar actions taken in similar situations for other Grantees generally. In the event of any conflict between this Agreement or the Plan on the one hand and the Management Stockholder’s Agreement and/or the Sale Participation Agreement on the other hand, the terms of the Management Stockholder’s Agreement and/or the Sale Participation Agreement shall control.
15.Signature in Counterparts. This Agreement may be signed in counterparts, each of which shall be an original, with the same effect as if the signatures thereto and hereto were upon the same instrument.
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IN WITNESS WHEREOF, this Agreement has been executed and delivered by the parties hereto.
| ENERGY FUTURE HOLDINGS CORP. | ||
| By: | /s/ Riz Chand | |
| GRANTEE | ||
| By: | /s/ John F. Young | |
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Exhibit 10(ii)
AMENDMENT NO. 1 TO THE
2007 STOCK INCENTIVE PLAN FOR KEY EMPLOYEES OF
ENERGY FUTURE HOLDINGS CORP. AND ITS AFFILIATES
Pursuant to the authority of the Executive Committee of Energy Future Holdings Corp., and the provisions of Section 10(b) thereof, the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates (the “Plan”) is hereby amended in the following respects only, effective as of December 23, 2008:
(1) Section 2 of the Plan is hereby amended to add the following subsection, and the remaining subsections shall be renumbered accordingly:
“(e) “Chief Executive Officer” means the person serving as the Chief Executive Officer of the Company or his authorized designee.”
(2) Section 3 of the Plan is hereby amended in its entirety to read as follows:
“(b) The Committee may delegate to the Chief Executive Officer and to other senior officers of the Company its duties under the Plan, subject to applicable law and such conditions and limitations as the Committee shall prescribe.”
(3) Section 4 of the Plan is hereby amended in its entirety to read as follows:
“4.Eligibility. The Committee or the Chief Executive Officer may from time to time make Grants under the Plan to such Employees, or other persons having a relationship with the Company or any other Service Recipient, and in such form and having such terms, conditions and limitations as the Committee or the Chief Executive Officer, as applicable, may determine. Notwithstanding the foregoing, the Chief Executive Officer shall not be authorized to make Grants to Employees serving on the Strategy & Policy Committee or to members of the Board, or to make Grants with respect to any Employee that cover, in the aggregate, in excess of 250,000 Stock Options and, for all other awards, more than 100,000 Shares, or, further, to make Grants attributable to, in the aggregate, more than 3,000,000 Shares in any calendar year, unless otherwise authorized by the Committee. The terms, conditions and limitations of each Grant under the Plan shall be set forth in a Grant Agreement, in a form approved by the Committee, consistent, however, with the terms of the Plan;provided, however, that such Grant Agreement shall contain provisions dealing with the treatment of Grants in the event of the termination of employment or other service relationship, death or disability of a Participant, and may also include provisions concerning the treatment of Grants in the event of a Change in Control. The term “Committee” as used in Section 5 shall also refer to the Chief Executive Officer, subject to the limitations prescribed herein.”
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IN WITNESS WHEREOF, and as conclusive evidence of the adoption of the foregoing instrument comprising Amendment No. 1 to the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates, the Executive Committee 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 14th day of July 2009.
| ENERGY FUTURE HOLDINGS CORP. | ||
| By: | /s/ M. Rizwan Chand | |
| M. Rizwan Chand | ||
Executive Vice President, Human Resources & Administration | ||
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Exhibit 10(jj)
John Young
Employment Arrangement
On February 15, 2010, the Organization and Compensation Committee (O&C Committee) of the Board approved several changes to John Young’s compensation arrangement. Pursuant to Mr. Young’s amended employment arrangement, effective January 1, 2010, Mr. Young’s base salary was increased from $1,000,000 to $1,200,000, and Mr. Young was granted a new cash-based retention incentive award (Retention Award). Under the terms of the Retention Award, Mr. Young is entitled to receive on September 30, 2012, to the extent Mr. Young remains employed by EFH Corp. on such date (with customary exceptions for death, disability and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 100% of the aggregate Executive Annual Incentive Plan award received by (or otherwise payable to) Mr. Young for fiscal years 2009, 2010 and 2011.
In addition, pursuant to Mr. Young’s amended employment arrangement, EFH Corp. will (i) purchase, on behalf of Mr. Young a 10 year term life insurance policy in an insured amount equal to $10,000,000 and (ii) adopt a supplemental retirement plan for Mr. Young 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.
Pursuant to Mr. Young’s amended employment arrangement, Mr. Young received a grant of 3,000,000 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. Young’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. Young surrendered to EFH Corp. 1,500,000 unvested performance-related stock options that were granted to Mr. Young when he joined EFH Corp.
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Exhibit 10(kk)
Employment Arrangements with Certain Executive Officers
EFH Corp. has approved several changes in EFH Corp.’s compensation program for its executive officers, as described below. Except as modified below, the executive officers’ current employment agreements with Company remain in full force and effect.
Base Salary
Effective January 1, 2010, the Company has increased the base salary for certain of its executive officers as follows: Mr. David Campbell’s, Luminant’s Chief Executive Officer, base salary will increase to $700,000; Mr. Paul Keglevic’s, EFH Corp.’s Chief Financial Officer, base salary will increase to $650,000; Mr. Burke’s, Chief Executive Officer of TXU Energy, base salary will increase to $630,000; Mr. Mac McFarland’s, Luminant’s Chief Commercial Officer, base salary will increase to $600,000; and Mr. Robert Walters’, EFH Corp.’s General Counsel, base salary will increase to $600,000. These increases were made after considering relevant market compensation data and are effective as of January 1, 2010.
Executive Annual Incentive Plan
Effective January 1, 2010, the Company has increased the annual target award under the Energy Future Holdings Corp. Executive Annual Incentive Plan (AIP), which is computed as a percentage of base salary, from 75% to 85% for Messrs. Keglevic, Campbell, McFarland, Walters and James Burke. These increases are effective for the 2010 AIP award period.
Long Term Incentive
The Company has approved a new retention incentive award, which will be included by amendment in certain executive officers’ employment agreements (Retention Award). Under the terms of the Retention Award, each of Messrs. Keglevic, Campbell, McFarland, Burke and Walters (collectively, the Executive Officers) will be entitled to receive on September 30, 2012, to the extent such Executive Officer remains employed by EFH Corp. on such date (with customary exceptions for death, disability and leaving for “good reason” or termination without “cause”), an additional one-time, lump-sum cash payment equal to 75% of the aggregate AIP award received by such executive officer for fiscal years 2009, 2010 and 2011.
Stock Options
The Company has approved the grant of new stock options to certain executive officers under the Stock Option Plan with a strike price of $3.50 per share (the fair market value of each share on the date of grant) as set forth in the table below. Certain of these stock options will vest 100% on September 30, 2014 (Cliff-Vested Options) and certain of these stock options will vest 20% per year over a five-year period beginning September 30, 2009 (Time-Vested Options). In connection with the grant of these new stock options, certain executive officers surrendered to EFH Corp. a portion of their currently outstanding unvested performance-related stock options as set forth in the table below.
Executive Officer | Cliff-Vested Options | Time-Vested Options | Surrendered Options | |||
David Campbell | 800,000 | 800,000 | 800,000 | |||
Paul Keglevic | 500,000 | 500,000 | 500,000 | |||
James Burke | 490,000 | 200,000 | 490,000 | |||
Mac McFarland | 400,000 | 400,000 | 400,000 | |||
Robert Walters | 400,000 | 400,000 | 400,000 |
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Exhibit 10(ll)
Joel D. Kaplan
Employment Arrangement
On October 19, 2009, Joel D. Kaplan was hired as the new Executive Vice President for Public Policy and External Affairs of Energy Future Holdings Corp. (the “Company”). In connection with his employment, the Company entered into an employment arrangement with Mr. Kaplan. As compensation for his services, Mr. Kaplan will be paid an annual base salary equal to $450,000 with the ability to earn an annual cash bonus equal to 70% of his base salary if he achieves certain annual performance targets established by the Board of Directors of the Company (the “Board”). Such annual cash bonus may be increased to an amount equal to 200% of his base salary based on achievement of certain superior annual performance targets established by the Board. The Company will also pay Mr. Kaplan a commuting allowance of $8,333 per month for the first two years of his employment with the Company. The employment arrangement also entitles Mr. Kaplan to receive other forms of customary compensation such as certain health and welfare benefits, certain perquisites and reimbursement of certain business expenses.
In addition, Mr. Kaplan received a grant of 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. 1,125,000 of Mr. Kaplan’s new stock options are time-vested options that will vest 20% per year over a five-year period beginning October 29, 2009 and 375,000 are performance vesting options, which vest in 20% increments on each of the first five anniversaries of December 31, 2009, subject to the Company’s achievement of the annual management EBITDA target for the given fiscal year (or certain cumulative performance targets) as detailed in the stock option agreements.
Mr. Kaplan’s employment arrangement includes customary non-compete and non-solicitation provisions that generally restrict Mr. Kaplan’s ability to compete with the Company or solicit its customers or employees for his own personal benefit during the term of the employment agreement and 18 months after the employment arrangement expires or is terminated.
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Exhibit 10(mm)
Richard J. Landy
Employment Arrangement
On January 4, 2010, Richard J. Landy was hired as the new Executive Vice President for Human Resources of Energy Future Holdings Corp. (the “Company”). In connection with his employment, the Company entered into an employment arrangement with Mr. Landy. As compensation for his services, Mr. Landy will be paid an annual base salary equal to $450,000 with the ability to earn an annual cash bonus equal to 65% of his base salary if he achieves certain annual performance targets established by the Board of Directors of the Company (the “Board”). Such annual cash bonus may be increased to an amount equal to 200% of his base salary based on achievement of certain superior annual performance targets established by the Board. The Company will also pay Mr. Landy a signing bonus of $100,000; provided that Mr. Landy must repay this amount in full to the Company in the event that Mr. Landy is terminated or resigns prior to the first anniversary of the effective date of his new employment agreement. The employment arrangement also entitles Mr. Landy to receive other forms of customary compensation such as certain relocation expenses, health and welfare benefits, certain perquisites and reimbursement of certain business expenses.
In addition, Mr. Landy received a grant of 400,000 time-vesting 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 which will vest on July 4, 2011 and the other half of which will vest on January 4, 2013.
Mr. Landy’s employment arrangement includes customary non-compete and non-solicitation provisions that generally restrict Mr. Landy’s ability to compete with the Company or solicit its customers or employees for his own personal benefit during the term of the employment agreement and 18 months after the employment arrangement expires or is terminated.
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Exhibit 10(nn)
CONSULTING AGREEMENT
THIS CONSULTING AGREEMENT (this “Agreement”), is dated as of February 18, 2010, effective as of October 10, 2009 (the “Commencement Date”), by and between Energy Future Holdings Corp., a Texas corporation (the “Company”), and Donald L. Evans (“Consultant”).
WHEREAS, the Company and Consultant previously entered into that certain Consulting Agreement, dated as of May 16, 2008, and effective October 10, 2007 (the “Original Agreement”) to govern the terms and conditions of the engagement of Consultant as non-executive Chairman (“Chairman”) of the Board of Directors of the Company (the “Board”);
WHEREAS, the Original Agreement expired on October 10, 2009 and, in accordance therewith, the Company and Consultant desire to extend the Consultant’s term as Chairman on the terms and conditions set forth herein; and
WHEREAS, the Parties acknowledge that the relationship between the Company and Consultant is an independent contractor relationship.
NOW, THEREFORE, in consideration of the mutual covenants and agreements set forth in this Agreement, the Company and Consultant hereby agree as follows:
1.Appointment; Consulting Arrangement. The Company hereby confirms Consultant’s appointment as Chairman effective as of the Commencement Date, and Consultant will, from time to time at the request of the Company and/or the Board upon reasonable advance notice, provide external and internal leadership and involvement in political and regulatory affairs of the Company and such other duties and responsibilities as shall be agreed upon between Consultant and the Company and/or the Board (collectively, the “Services”).
Nothing in this Agreement shall be deemed to affect Consultant’s status as a “Non-Employee Director” under Article XII of the Company’s Certificate of Formation, as amended.
2.Term; Termination. The term of Consultant’s tenure as Chairman (the “Consulting Term”) commenced as of Commencement Date and shall terminate on the third anniversary of the Commencement Date (the “Initial Expiration Date”), unless extended by the mutual agreement of the parties at least ninety (90) days prior to the Initial Expiration Date for up to an additional three years. In the event the parties agree to extend the Consulting Term beyond the Initial Expiration Date, the terms of this Agreement shall be revised at the time of such extension in light of the existing circumstances at the time. The Company or Consultant may terminate this Agreement by giving thirty (30) days prior written notice to the other party.
During the Consulting Term, Consultant agrees, to the extent necessary to reasonably discharge the duties and responsibilities assigned to Consultant hereunder, to use Consultant’s commercially reasonable efforts and such time as is reasonably required to perform such duties and responsibilities. Consultant may (i) (A) continue to serve on the boards of directors of the entities listed onSchedule 1 attached hereto and (B) serve on the boards of directors of any investment fund or other pooled investment vehicle that is a subsidiary or an affiliate of those entities listed onSchedule 1, including, without limitation, any such subsidiary or affiliate that may be formed after the date hereof, (ii) with the prior written consent of the Board (which consent shall not be unreasonably withheld), serve on the board of directors of other for-profit companies that do not compete with the Company, (iii) serve on civic or charitable boards or committees, and (iv) manage personal investments.
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3.Compensation.
(a)Base Compensation. Consultant shall be paid in cash an annual advisory fee by the Company equal to $2,000,000 per year (the “Base Fee”) in quarterly installments of $500,000, payable on the last day of every third month during the Consulting Term.
(b)Equity Arrangements.
(i)Stock Purchases. Twice per fiscal year, during the seven (7) day period beginning on the date the Company releases earnings for each of the first and third quarters of each fiscal year of the Company, Consultant shall have the right, but not the obligation, to purchase from the Company shares of Common Stock, no par value, of the Company (“Common Stock”);provided, that, the aggregate fair market value of the shares of Common Stock (determined as of the date(s) of purchase) purchased by Consultant in any one fiscal year of the Company pursuant to this Section 3(b)(i) shall not exceed $2,000,000. The purchase price of per share of Common Stock purchased pursuant to this Section 3(b)(i) shall be equal to the fair market value (determined in accordance with the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates, as amended from time to time (the “Plan”)) (“Fair Market Value”) on the date of purchase. Any shares purchased by the Consultant pursuant to this Section 3(b)(i) shall be promptly evidenced by book entry on the Company’s stock record and no stock certificates will be issued to Consultant.
(ii)Governing Documents. The rights and obligations of Consultant relating to the Common Stock purchased directly by Consultant from the Company pursuant to Section 3(b)(i) hereof shall be governed by the terms and conditions of a Stock Purchase Agreement, a Stockholder Agreement, and a Sale Participation Agreement, to be entered into between Consultant and the Company (collectively, the “Equity Documents”). The rights and obligations of Consultant relating to the Common Stock issued or that may be issued to Consultant pursuant to the Non-Qualified Stock Option Agreement, dated May 16, 2008, and the Restricted Stock Award Agreement, dated May 16, 2008, shall continue to be governed by the terms of such agreements, to the extent applicable, and by the terms of the Sale Participation Agreement, dated May 16, 2008, and the Stockholder Agreement, dated May 16, 2008;provided,however, the Common Stock issued upon exercise of the previously granted stock options (or any subsequently granted option to purchase shares of Common Stock) shall not be subject to any provisions in the foregoing documents with respect to put rights, call rights, or transfer restrictions.
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(c)If Consultant Terminates the Agreement or if Company Terminates the Agreement for Cause. In the event that Consultant terminates the Agreement before the end of the Consulting Term or Company terminates the Agreement for Cause (as defined herein), (i) Consultant shall forfeit any right to compensation not yet granted or paid under Section 3(a) or 3(b), except a pro-rated portion of the Base Fee not yet paid by Company but earned by Consultant prior to the termination of the Agreement (calculated as set forth below); and (ii) Consultant shall be entitled, subject to the requirements of Section 4(a), to receive reimbursement for any reasonable expenses incurred in connection with the performance of Services prior to the end of the Consulting Term. The calculation of any Base Fee to be paid to Consultant under this Section 3(c) following termination of the Agreement shall be determined by multiplying $500,000 by a fraction, the numerator of which is the number of days commencing on the first day of the quarter in which such termination occurred and ending on the date of termination and the denominator of which is the number of days in the quarter.
(d)If Company Terminates the Agreement Without Cause. In the event that Company terminates the Agreement before the end of the Consulting Term for any reason other than Cause (as defined below), Company shall provide to Consultant the following: (i) any unpaid Base Fee (whether or not earned at the time of termination) that would have been paid to Consultant if the Services had continued until the end of the Consulting Term, which Base Fee shall be paid in a single lump sum within thirty (30) days of the termination of the Agreement, and (ii) subject to the requirements of Section 4(a), reimbursement for any reasonable expenses incurred in connection with the performance of Services prior to the end of the Term.
(e)Definitions. For purposes of this Agreement, the terms specified below shall be given the following meanings:
(i)Cause. “Cause” shall be defined as: (A) Consultant’s continued failure to substantially perform the Services which continues beyond ten (10) days following the date on which a written demand for substantial performance is delivered to Consultant by the Company (the “Cure Period”); (B) if, in performing Services for Company, Consultant engages in conduct that constitutes (1) a material breach of his fiduciary duty to the Company or its shareholders (including, without limitation, a material breach of the restrictive covenants under this Agreement, which breach is not cured, if curable, during the Cure Period after written notice from the Company) or (2) gross neglect or (3) misconduct resulting in material economic harm to the Company, or (C) upon the conviction of the Consultant for, or the plea of guilty ornolo contendere by Consultant to, any crime involving moral turpitude and/or any felony.
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4.Expenses and Administrative Support.
(a) In addition to the compensation payable to Consultant pursuant to Section 3 hereof, Consultant is authorized to incur reasonable and customary business expenses incurred on the Company’s behalf in connection with the performance of Services hereunder, including, without limitation, expenditures for business travel, lodgings, meals and entertainment expenses (“Business Expenses”). The Company shall, subject to the requirements of this Section 4(a), reimburse Consultant for all Business Expenses upon presentation by Consultant, from time to time, of appropriately itemized accounts of such expenditures. Consultant shall provide such itemized accounts within sixty (60) days after the expense is incurred and the Company shall reimburse Consultant within fifteen (15) days after receipt of such account. Expenses shall be reimbursed as soon as practicable following the Company’s receipt of such accounts, but in no event later than the March 15th following the end of the calendar year in which the expenses were incurred; provided, however, the Company’s obligation to reimburse reasonable expenses will terminate in the event Consultant does not request reimbursement in a timely manner to allow the expense to be paid prior to such date.
(b) Consultant shall be provided with an office and administrative assistant, each in Midland, Texas, as well as any professional resources needed to discharge his responsibilities, in each case at the sole expense of the Company.
(c) The Company shall reimburse Consultant, or pay directly, upon submission to the Company of a statement for services, the amount payable by Consultant to the attorney(s) of Consultant’s choice that Consultant has retained to advise Consultant with regard to the negotiation and execution of this Agreement;provided,however, that (i) the fees charged by such attorney(s) are computed at the standard hourly rate for such attorney(s), and (ii) such reimbursement or payment shall not exceed, in the aggregate, $20,000.
5.Status; Taxes.
(a)Status of Consultant. It is the intention of the parties hereto that, in performing the Services, Consultant shall act as and be deemed in all respects to be an independent contractor, and not for any purpose as an employee or agent of the Company except on authority specifically so delegated to Consultant to act as agent, and he shall not represent to the contrary to any person. Consultant shall only consult, render advice and perform such tasks as Consultant determines are necessary to provide the Services. Although the Company may specify the tasks to be performed by Consultant and may control and direct him in that regard, the Company shall not control or direct Consultant as to the details or means by which such tasks are accomplished.
(b)Taxes. It is intended that the fees paid hereunder shall constitute revenues to Consultant. Subject to the following provisions of this Section 5(b), Consultant shall have full responsibility and the Company shall have no responsibility for satisfying any liability for any federal, state or local income or other taxes required by law to be paid with respect to the fees paid hereunder.
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(c) Consultant shall not be entitled to participate in any employee benefit plans or other programs in which participation is restricted to employees of the Company.
6.Nondisclosure of Confidential Information and Non-Disparagement.
(a)Non-Disclosure of Confidential Information. Consultant shall not, without the prior written consent of the Company, use, divulge, disclose or make accessible to any other person, firm, partnership, corporation or other entity any Confidential Information pertaining to the business of the Company, its parent or any of its subsidiaries (collectively, the “Company Group”), except (i) while providing Services to the Company, in the business of and for the benefit of the Company, or (ii) as required by law,provided,however, that if Consultant receives a subpoena to produce any Confidential Information, Consultant will notify the Company immediately so that the Company can seek a protective order, if desired. For purposes of this Section 6, “Confidential Information” shall mean non-public information concerning the financial data, strategic business plans, product development (or other proprietary product data), customer lists, marketing, acquisition and divestiture plans and other non-public, proprietary and confidential information of the Company, its shareholders, directors, officers or any of their respective affiliates that, in any case, is not otherwise available to the public (other than by Consultant’s breach of the terms hereof). Consultant acknowledges that the Confidential Information of the Company is valuable, special and unique to its business and is information on which such business depends, is proprietary to the Company, and that the Company wishes to protect such Confidential Information by keeping it secret and confidential for the sole use and benefit of the Company. Consultant will take all steps necessary and reasonably requested by the management of the Company, to ensure that all such Confidential Information is kept secret and confidential for the sole use and benefit of the Company.
(b)Non-Disparagement.
(i) Consultant agrees not to defame, or make any false or disparaging statements about the Company and/or its Affiliates, or any of their respective products, services, finances, financial condition, capabilities or other aspect of or any of their respective businesses, in any medium to any person or entity; or otherwise, to take any action that primarily is designed to have the effect of discouraging any employee, lessor, licensor, customer, supplier, or other business associate of the Company from maintaining its business relationships with the Company and/or its Affiliates (any such statement or act a “Prohibited Statement” or “Prohibited Action”). Consultant shall be permitted to issue press releases, make statements to the press, give guidance to the market or make statements to regulators, governmental agencies, legislators or other governmental officials; or otherwise to take such actions necessary in connection with Consultant’s duties and responsibilities under this Agreement, without such statements or actions being considered a Prohibited Statement or Prohibited Action under this Agreement.
(ii) The Company hereby agrees that Company and its officers shall not defame, or make any disparaging statements in any medium to any person or entity about Consultant.
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(iii) Notwithstanding any provision of this Section 6(b) to the contrary, (A) both Consultant and the Company (including the Board and its executive officers) may (1) confer in confidence with their legal representatives and make truthful statements as required by law and (2) make private statements to any officer, director or employee of the Company or any of its affiliates; and (B) nothing herein shall prevent any person from (1) responding publicly to incorrect, disparaging or derogatory public statements to the extent reasonably necessary to correct or refute such public statement or (2) making any truthful statement to the extent (x) necessary with respect to any litigation, arbitration or mediation involving this Agreement (or any Exhibit hereto) or any other agreement among or between any party hereto or (y) required by law or by any court, arbitrator, mediator or administrative or legislative body (including any committee thereof) with actual or apparent jurisdiction to order such person to disclose or make accessible such information.
(iv) By signing this Agreement, Consultant agrees and acknowledges that Consultant is making, after the opportunity to confer with counsel, a knowing, voluntary and intelligent waiver of rights Consultant may have to make disparaging comments regarding the Company and/or its affiliates, including rights under the First Amendment to the United States Constitution and any other applicable federal and state constitutional rights.
(c) The non-disclosure and non-disparagement obligations contained in this Section 6 shall continue in full force and effect after the conclusion of Consultant’s engagement with the Company and shall survive the expiration, termination, or cancellation of this Agreement, in each case in accordance with their respective terms, regardless of the reason for such termination or restriction. Consultant’s obligations with respect to any specific Confidential Information shall cease only when that specific portion of the Confidential Information becomes publicly known, other than as a result of disclosure by Consultant, in its entirety, without combining portions of such Confidential Information with other Confidential Information obtained separately
7.Indemnification. The Company shall, to the fullest extent permitted by law, indemnify and hold Consultant harmless if Consultant is, or is threatened to be, made a party to or involved in any other capacity in any threatened, pending or completed action, suit or proceeding, whether civil, criminal, administrative or investigative (including any action by or in the right of the Company or its affiliates), by reason of any actions or omissions or alleged acts or omissions arising out of Consultant’s activities either on behalf of the Company or its affiliates or in what Consultant reasonably believed to be in furtherance of the interests of any of the above or arising out of or in connection with any of the above, if such activities were performed in good faith either on behalf of the Company or its affiliates and in a manner reasonably believed by Consultant to be within the scope of the authority conferred to Consultant or conferred by law, against losses, damages or expenses for which Consultant has not otherwise been reimbursed (including attorneys’ fees, judgments, fines and amounts paid in settlement) and which were actually incurred by Consultant in connection with such action, suit or proceeding. In addition, Consultant shall be covered, in respect of Consultant’s activities as a director of the Company, by the Company’s Directors and Officers liability policy or other comparable policies obtained by the Company’s successors, to the fullest extent permitted by such policies.
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8.Severability. If any provision of this Agreement shall be declared to be invalid or unenforceable, in whole or in part, such invalidity or unenforceability shall not affect the remaining provisions hereof which shall remain in full force and effect.
9.Entire Agreement. The provisions contained herein constitute the entire agreement between the parties with respect to the subject matter of this Agreement and supersede any and all prior agreements, understandings and communications between the parties, oral or written, with respect to such subject matter.
10.Modifications. Any waiver, alteration, amendment or modification of any provisions of this Agreement shall not be valid unless in writing and signed by the Company and the Consultant.
11.Assignment; Binding Effect. Neither party may assign any of its or his rights or delegate any of its or his duties under this Agreement without the consent of the other and any attempted assignment in violation of this provision shall be void. Subject to the limitations set forth in this Section 11, this Agreement shall be binding upon and inure to the benefit of the successors-in-interest and permitted assigns of the Company and Consultant. The Company shall require any successor to all or substantially all of the Company’s assets or business to assume this Agreement.
12.Notice. All notices and other communications required or permitted under this Agreement shall be made in writing and shall be deemed given if delivered personally, sent by registered or certified mail (e.g., the equivalent of U.S. registered mail), return receipt requested, postage prepaid, or sent by nationally recognized overnight courier service, addressed as follows:
If to the Company:
Energy Future Holdings Corp.
1601 Bryan Street
Dallas, Texas 75201-3411
Attention: General Counsel
If to Consultant:
Donald L. Evans
500 West Texas Avenue
Suite 960
Midland, TX 79701
(432) 684-7721
or to such other addresses as a party shall designate in the manner provided in this Section 12. Any notice or other communication shall be deemed given (a) on the date three (3) business days after it shall have been mailed, if sent by certified mail, (b) on the date one (1) business day after it shall have been given to a nationally-recognized overnight courier service or (c) upon the electronic confirmation of facsimile.
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13.Choice of Law. This Agreement shall be governed by and construed in accordance with the law of the State of Texas, without regard to conflicts of laws principles. The Parties agree that the proper venue and jurisdiction for any cause of action relating to the Agreement shall be in Dallas County, Texas. If the Consultant substantially prevails on his substantive legal claims, the Company shall reimburse all legal fees and costs incurred by the Consultant to resolve the dispute.
14.Section Headings. The section headings contained in this Agreement are for reference purposes only and shall not affect in any way the meaning or interpretation of this Agreement.
15.Counterparts. This Agreement may be executed in one or more counterparts (including by facsimile), which shall, collectively and separately, constitute one agreement.
16.Section 409A. To the extent applicable, this Agreement 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 Agreement 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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IN WITNESS WHEREOF, the parties hereto have duly executed this Agreement as of the date first above written.
/s/ Donald L. Evans | ||||
| By: | Donald L. Evans | |||
| ENERGY FUTURE HOLDINGS CORP. | ||||
/s/ Lisa M. Winston | ||||
| By: | Lisa M. Winston | |||
| SVP, Associate General Counsel and Corporate Secretary | ||||
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SCHEDULE 1
ENTITIES FOR WHICH CONSULTANT IS A DIRECTOR
| 1. | George W. Bush Library Foundation |
| 2. | Quintana Energy Partners |
| 3. | Energy Capital Partners |
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Exhibit 10(oo)
ENERGY FUTURE HOLDINGS CORP. KEY EMPLOYEE
AMENDED AND RESTATED NON-QUALIFIED STOCK OPTION AGREEMENT
THIS AMENDED AND RESTATED NON-QUALIFIED STOCK OPTION AGREEMENT (“Agreement”), dated as of December 1, 2009 (the “Effective Date”), is made by and between Energy Future Holdings Corp., a Texas corporation (hereinafter referred to as the “Company”), and the individual whose name is set forth on the signature page hereof (hereinafter referred to as the “Optionee”). Any capitalized terms used but not otherwise defined herein shall have the meaning set forth in the 2007 Stock Incentive Plan for Key Employees of Energy Future Holdings Corp. and its Affiliates or any successor plan (the “Plan”).
WHEREAS, the Organization and Compensation Committee of the Board of the Company (the “Committee”) has determined that it would be to the advantage and best interest of the Company and its shareholders to grant the Option provided for herein to the Optionee as an incentive for increased efforts during his term of employment with the Company or its Subsidiaries or Affiliates, and has advised the Company thereof and authorized the undersigned officers to issue said Option;
WHEREAS, the Company wishes to act consistently with the Plan, the terms of which are hereby incorporated by reference and made a part of this Agreement; and
WHEREAS, the parties previously entered into a Non-Qualified Stock Option Agreement, dated May 20, 2008, pursuant to which the Company granted stock options to the Optionee (the “Original Option Agreement”), and the parties desire to enter into this Agreement to (i) cancel, immediately prior to the Effective Date hereof, all unvested performance-related options subject to the award, and (ii) grant additional time-based vesting options on the terms and conditions set forth herein.
NOW, THEREFORE, in consideration of the mutual covenants herein contained and other good and valuable consideration, receipt of which is hereby acknowledged, the parties hereto do hereby agree as follows:
ARTICLE I
DEFINITIONS
Whenever the following terms are used in this Agreement, they shall have the meaning specified below unless the context clearly indicates to the contrary.
Section 1.1Cause
“Cause” shall mean “Cause” as such term may be defined in any employment agreement or change-in-control agreement in effect at the time of termination of employment between the Optionee and the Company or any of its Subsidiaries or Affiliates, or, if there is no such employment or change-in-control agreement, “Cause” shall mean, with respect to an Optionee: (i) if, in carrying out his duties to the Company, the Optionee engages in conduct that constitutes (a) a material breach of his fiduciary duty to the Company or its shareholders (including, without limitation a material breach or attempted breach of the restrictive covenants under the Management Stockholder’s Agreement), (b) gross neglect or (c) gross misconduct resulting in material economic harm to the Company, provided that any such conduct described in (a), (b) or (c) is not cured within ten (10) business days after the Optionee receives from the Company written notice thereof, or (ii) Optionee’s conviction of, or entry of a plea of guilty or nolo contendere for, a felony or other crime involving moral turpitude.
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Section 1.2Cliff Vesting Option
“Cliff Vesting Option” shall have the meaning given such term in Section 2.1 hereof.
Section 1.3Disability
“Disability” shall mean “Disability” as such term is defined in any employment agreement between the Optionee and the Company or any of its Subsidiaries, or, if there is no such employment agreement, “Disability” shall mean the Optionee’s physical or mental incapacitation and consequent inability for a period of six consecutive months to perform the Optionee’s duties;provided,however, in the event the Company temporarily replaces the Optionee, or transfers the Optionee’s duties or responsibilities to another individual, on account of the Optionee’s mental or physical impairment for a period of time which is covered by the Company’s short term disability plan, the Optionee’s employment shall not be deemed terminated by the Company and the Optionee shall not be able to resign with Good Reason.
Section 1.4Extended Exercise Date
“Extended Exercise Date”shall mean the earlier of: (i) the tenth anniversary of the Grant Date; or (ii) the later of the date: (A) one hundred and eighty (180) days following the date of an Optionee’s termination of employment with the Company and all Service Recipients and (B) thirty (30) days following the first date on which the Optionee could exercise the Option and immediately resell the Shares acquired upon such exercise for cash consideration.
Section 1.5Fair Market Value
“Fair Market Value” shall mean, for the purposes of the Plan and this Agreement and notwithstanding the definition contained in the Plan: (i) if there is a public market for the Shares on such date, the average of the high and low closing bid prices of the shares of Common Stock on such stock exchange on which the Shares are principally trading on the date in question, or, if there were no sales on such date, on the closest preceding date on which there were sales of Shares or, (ii) if there is no public market for the Shares, on a per Share basis, the fair market value of the Common Stock on any given date, as determined reasonably and in good faith by the Board, which shall not take into account any minority interest discount and shall not take into account a discount for illiquidity of shares of Common Stock held by an Optionee in excess of any illiquidity discount applicable to shares of Common Stock generally; provided that if the Board’s determination under this clause (ii) is not based on a valuation completed by an independent valuation firm within the 6 months preceding the Board’s determination, the Optionee may require the Company to retain an independent valuation firm to determine the fair market value (and the Company will bear the cost of such appraisal, unless the appraised value is 110% or less of the fair market value as determined by the Board, in which case the Optionee will bear the cost of such appraisal).
Section 1.6Good Reason
“Good Reason” shall mean “Good Reason” as such term may be defined in any employment agreement or change-in-control agreement in effect at the time of termination of employment between the Optionee and the Company or any of its Subsidiaries or Affiliates, or, if there is no such employment or change-in-control agreement, “Good Reason” shall mean (i) a reduction in the Optionee’s base salary or the Optionee’s annual incentive compensation opportunity (other than a general reduction in base salary or annual incentive compensation opportunities that affects all salaried employees of the Company equally); (ii) a transfer of the Optionee’s primary workplace by more than thirty-five (35) miles from the current workplace; (iii) a substantial adverse change in the Optionee’s duties and responsibilities; (iv) any material breach by the Company of this Agreement, the Management Stockholder’s Agreement, or the Optionee’s employment agreement; or (v) an adverse change after the October 10, 2007 in the Optionee’s line of reporting to superior officers pursuant to the terms of his employment agreement or change-in-control agreement;provided,however, that any isolated, insubstantial and inadvertent failure by the Company that is not in bad faith and is cured within ten (10) business days after the Optionee gives the Company written notice of any such event set forth above, shall not constitute Good Reason.
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Section 1.7Grant Date
“Grant Date” means the date the Option, or a portion thereof, is granted as specified for each of the Original Time Option, the Performance Option, and the Cliff Vesting Option in Section 2.1 hereof.
Section 1.8Management Stockholder’s Agreement
“Management Stockholder’s Agreement” shall mean the Management Stockholder’s Agreement between the Optionee and the Company.
Section 1.9Option
“Option” shall mean the aggregate of the Original Time Option, the Performance Option, and the Cliff Vesting Option.
Section 1.10Original Time Option
“Original Time Option” shall have the meaning given such term in Section 2.1 hereof.
Section 1.11Parent
“Parent” shall mean Texas Energy Future Holdings Limited Partnership, a Delaware Limited Partnership.
Section 1.12Performance Option
“Performance Option” shall have the meaning given such term in Section 2.1 hereof.
Section 1.13Retirement
“Retirement” shall mean the Optionee's retirement at age 55 or over after having been employed by the Company or a Subsidiary or Parent for at least ten (10) consecutive years (with at least five consecutive years of employment following October 10, 2007).
Section 1.14Secretary
“Secretary” shall mean the Secretary of the Company.
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ARTICLE II
GRANT OF OPTIONS
Section 2.1Grant of Options
This Agreement evidences the grant to the Optionee, for good and valuable consideration and in each case on the terms and conditions set forth in this Agreement, of the following:
(a) an option to purchase 800,000 Shares of Common Stock, previously granted to Optionee on May 20, 2008, which shall vest in accordance with the provisions of Section 3.1(a)(i) hereof (the “Original Time Option”);
(b) an option to purchase 640,000 Shares of Common Stock, granted to the Optionee on December 1, 2009, which shall vest in accordance with the provisions of Section 3.1(a)(ii) hereof (the “Cliff Vesting Option”); and
(c) an option to purchase 160,000 Shares of Common Stock, previously granted to the Optionee on May 20, 2008, which vested prior to the Effective Date hereof (the “Performance Option”). The Performance Option was previously evidenced by the Original Option Agreement, and originally consisted of the right to purchase an aggregate of 800,000 Shares of Common Stock. The Optionee acknowledges that his acceptance of this Agreement constitutes his agreement to the surrender and cancellation in full of all of his right, title and interest in the right to purchase 640,000 Shares of Common Stock, which were previously awarded to the Optionee as part of the Performance Option pursuant to the Original Option Agreement, with no further obligations of the Company thereunder.
Section 2.2Exercise Price
Subject to Section 2.4, the exercise price of the Shares of Common Stock covered by the Option shall be equal to (a) $5.00 per Share for the Original Time Option and the Performance Option, and (b) $3.50 per Share for the Cliff Vesting Option (each applicable price, the “Exercise Price”).
Section 2.3No Guarantee of Employment
Nothing in this Agreement or in the Plan shall confer upon the Optionee any right to continued employment by the Company or any Subsidiary or Affiliate or shall interfere with or restrict in any way the rights of the Company and its Subsidiaries or Affiliates, which are hereby expressly reserved, to terminate the employment of the Optionee at any time for any reason whatsoever, with or without Cause, subject to the applicable provisions of, if any, the Optionee’s employment agreement with the Company.
Section 2.4Adjustments to Option
The Option shall be subject to the adjustment provisions of Sections 8 and 9 of the Plan,provided,however, that in the event of the payment of an extraordinary dividend by the Company to its stockholders, then: the Exercise Price of the Option shall be reduced by the amount of the dividend paid, but only to the extent the Committee determines it to be permitted under applicable tax laws and not to have adverse tax consequences to the Optionee under Section 409A of the Code; and, if such reduction cannot be fully effected due to such tax laws without adverse tax consequences to the Optionee, then the Company shall pay to the Optionee a cash payment, on a per Share basis, equal to the balance of the amount of the dividend not permitted to be applied to reduce the Exercise Price of the applicable Option as follows: (a) for each Share subject to a vested Option, immediately upon the date of such dividend payment; and (b), for each Share subject to an unvested Option, on the date on which such Option becomes vested and exercisable with respect to such Share.
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ARTICLE III
PERIOD OF EXERCISABILITY
Section 3.1Commencement of Exercisability
(a) So long as the Optionee continues to be employed by the Company or any other Service Recipients, the Option shall become exercisable pursuant to the following schedules:
(i)Original Time Option. The Original Time Option shall become vested and exercisable with respect to 20% of the Shares subject to the Original Time Option on each of the first five anniversaries of October 10, 2007. However, upon the occurrence of Optionee’s termination of employment without Cause or resignation for Good Reason (in each case following the occurrence of a Change in Control), the Original Time Option shall become immediately exercisable as to 100% of the Shares of Common Stock subject to such Option immediately prior to the Change in Control.
(ii)Cliff Vesting Option. The Cliff Vesting Option shall become vested and exercisable in accordance with the following schedule, provided the Optionee has remained continuously employed by the Company or any other Service Recipients through the applicable vesting dates:
Vesting Date | Cumulative Percentage of Shares Subject to the Cliff Vesting Option that are Vested and Exercisable | |
September 30, 2012 | 50% | |
September 30, 2014 | 50% | |
However, upon the occurrence of a Change in Control, the Cliff Vesting Option shall become immediately exercisable as to 100% of the Shares of Common Stock subject to such Option immediately prior to the Change in Control, provided the Optionee remains continuously employed by the Company or any other Service Recipients on the date such Change in Control occurs.
(iii)Performance Option. The Performance Option is fully vested and exercisable as of the Effective Date hereof.
(b) Notwithstanding anything to the contrary in this Section 3.1, no Option shall become exercisable as to any additional Shares of Common Stock following the termination of employment of the Optionee for any reason and any Option, which is unexercisable as of the Optionee’s termination of employment, shall immediately expire without payment therefor.
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Section 3.2Expiration of Option
Except as otherwise provided in Section 5 or 6 of the Management Stockholder’s Agreement, the Optionee may not exercise the Option, or any portion thereof, to any extent after the first to occur of the following events:
(a) The tenth anniversary of the applicable Grant Date;
(b) The first anniversary of the date of the Optionee’s termination of employment with the Company and all Service Recipients, if the Optionee’s employment is terminated by reason of death or Disability;
(c) Immediately upon the date of an Optionee’s termination of employment by the Company and all Service Recipients for Cause;
(d) Thirty (30) days after the date of an Optionee’s resignation from employment with the Company and all Service Recipients without Good Reason (except due to death or Disability);
(e) One hundred and eighty (180) days after the date of (i) an Optionee’s resignation from employment with the Company and all Service Recipients for Good Reason; (ii) an Optionee’s Retirement; or (iii) an Optionee’s termination of employment by the Company and all Service Recipients without Cause (for any reason other than as set forth in Section 3.2(b)), in the event such termination listed in (i), (ii), or (iii) occurs prior to the third anniversary of October 10, 2007;
(f) The Extended Exercise Date in the event of (i) an Optionee’s resignation from employment with the Company and all Service Recipients for Good Reason; (ii) an Optionee’s Retirement; or (iii) an Optionee’s termination of employment by the Company and all Service Recipients without Cause (for any reason other than as set forth in Sections 3.2(b)), including upon nonrenewal of Optionee’s existing employment agreement by the Company or other applicable Service Recipient, and any such termination listed in (i), (ii) or (iii) occurs on or after the third anniversary of October 10, 2007;
(g) Immediately upon the date of an Optionee’s breach of the provisions of Section 22(a)(ii) of the Management Stockholder’s Agreement; or
(h) At the discretion of the Committee pursuant to Section 9 of the Plan, but only to the extent the Committee determines it to be permitted under applicable tax laws and not to have adverse tax consequences to the Optionee under Section 409A of the Code.
ARTICLE IV
EXERCISE OF OPTION
Section 4.1Person Eligible to Exercise
During the lifetime of the Optionee, only the Optionee (or his duly authorized legal representative) may exercise the Option or any portion thereof. After the death of the Optionee, any exercisable portion of the Option may, prior to the time when an Option becomes unexercisable under Section 3.2, be exercised by his personal representative or by any person empowered to do so under the Optionee’s will or under the then applicable laws of descent and distribution.
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Section 4.2Partial Exercise
Any exercisable portion of the Option or the entire Option, if then wholly exercisable, may be exercised in whole or in part at any time prior to the time when the Option or portion thereof becomes unexercisable under Section 3.2;provided,however, that any partial exercise shall be for whole Shares of Common Stock only.
Section 4.3Manner of Exercise
The Option, or any exercisable portion thereof, may be exercised solely by delivering to the Secretary or her office all of the following prior to the time when the Option or such portion becomes unexercisable under Section 3.2:
(a) Notice in writing signed by the Optionee or the other person then entitled to exercise the Option or portion thereof, stating that the Option or portion thereof is thereby exercised, such notice complying with all applicable rules established by the Committee;
(b) (i) Full payment (in cash, by check, or by a combination thereof or through tender of previously owned Shares (any such Shares valued at Fair Market Value on the date of exercise) that the Participant has held for at least six months (or such other period as may be required by the Company’s accountants but only to the extent required to avoid liability accounting under FAS 123(R) or any successor standard thereto)) for the Shares with respect to which such Option or portion thereof is exercised or (ii) indication that the Optionee elects to have the number of Shares that would otherwise be issued to the Optionee reduced by a number of Shares having an equivalent Fair Market Value to the payment that would otherwise be made by the Optionee to the Company pursuant to clause (i) of this subsection (b);
(c) (i) Full payment (in cash or by check or by a combination thereof) to satisfy the minimum withholding tax obligation with respect to which such Option or portion thereof is exercised; or (ii) notice in writing that the Optionee elects to have the number of Shares that would otherwise be issued to the Optionee reduced by a number of Shares having an equivalent Fair Market Value to the payment that would otherwise be made by the Optionee to the Company pursuant to clause (i) of this subsection (c);
(d) A bona fide written representation and agreement, in a form satisfactory to the Committee, signed by the Optionee or other person then entitled to exercise such Option or portion thereof, stating that the Shares of Common Stock are being acquired for his own account, for investment and without any present intention of distributing or reselling said Shares or any of them except as may be permitted under the Securities Act of 1933, as amended (the “Act”), and then applicable rules and regulations thereunder, and that the Optionee or other person then entitled to exercise such Option or portion thereof will indemnify the Company against and hold it free and harmless from any loss, damage, expense or liability resulting to the Company if any sale or distribution of the Shares by such person is contrary to the representation and agreement referred to above;provided,however, that the Committee may, in its reasonable discretion, take whatever additional actions it deems reasonably necessary to ensure the observance and performance of such representation and agreement and to effect compliance with the Act and any other federal or state securities laws or regulations; and
(e) In the event the Option or portion thereof shall be exercised pursuant to Section 4.1 by any person or persons other than the Optionee, appropriate proof of the right of such person or persons to exercise the Option.
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Without limiting the generality of the foregoing, the Committee may require an opinion of counsel acceptable to it to the effect that any subsequent transfer of Shares acquired on exercise of an Option does not violate the Act, and may issue stop-transfer orders covering such Shares. Share certificates evidencing stock issued on exercise of this Option shall bear an appropriate legend referring to the provisions of subsection (d) above and the agreements herein. The written representation and agreement referred to in subsection (d) above shall, however, not be required if the Shares to be issued pursuant to such exercise have been registered under the Act, and such registration is then effective in respect of such Shares.
Section 4.4Conditions to Issuance of Stock Certificates
The Shares of stock deliverable upon the exercise of the Option, or any portion thereof, may be either previously authorized but unissued Shares or issued Shares, which have then been reacquired by the Company. Such Shares shall be fully paid and nonassessable. The Company shall not be required to issue or deliver any certificate or certificates for Shares of stock purchased (if certified, or if not certified, register the issuance of such Shares on its books and records) upon the exercise of the Option or a portion thereof prior to fulfillment of all of the following conditions:
(a) The obtaining of approval or other clearance from any state or federal governmental agency which the Committee shall, in its reasonable and good faith discretion, determine to be necessary or advisable;
(b) The execution by the Optionee of the Management Stockholder’s Agreement and a Sale Participation Agreement; and
(c) The lapse of such reasonable period of time following the exercise of the Option as the Committee may from time to time establish for reasons of administrative convenience or as may otherwise be required by applicable law.
Section 4.5Rights as Stockholder
Except as otherwise provided in Section 2.4 of this Agreement, the holder of an Option shall not be, nor have any of the rights or privileges of, a stockholder of the Company with respect to any Shares purchasable upon the exercise of the Option or any portion thereof unless and until certificates representing such Shares shall have been issued by the Company to such holder or the Shares have otherwise been recorded in the records of the Company as owned by such holder.
ARTICLE V
MISCELLANEOUS
Section 5.1Administration
The Committee shall have the power to interpret the Plan and this Agreement and to adopt, interpret or revoke rules for the administration, interpretation and application of the Plan. All actions taken and all interpretations and determinations made by the Committee shall be final and binding upon the Optionee, the Company and all other interested persons. No member of the Committee shall be personally liable for any action, determination or interpretation made in good faith with respect to the Plan or the Option. In its absolute discretion, the Board may at any time and from time to time exercise any and all rights and duties of the Committee under the Plan and this Agreement.
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Section 5.2Option Not Transferable
Neither the Option nor any interest or right therein or part thereof shall be liable for the debts, contracts or engagements of the Optionee or his successors in interest or shall be subject to disposition by transfer, alienation, anticipation, pledge, encumbrance, assignment or any other means whether such disposition be voluntary or involuntary or by operation of law by judgment, levy, attachment, garnishment or any other legal or equitable proceedings (including bankruptcy), and any attempted disposition thereof shall be null and void and of no effect;provided,however, that this Section 5.2 shall not prevent transfers by will or by the applicable laws of descent and distribution.
Section 5.3Notices
Any notice to be given under the terms of this Agreement to the Company shall be addressed to the Company in care of its Secretary, and any notice to be given to the Optionee shall be addressed to him at the last address on file with the Company. By a notice given pursuant to this Section 5.3 either party may hereafter designate a different address for notices to be given to that party. Any notice, which is required to be given to the Optionee, shall, if the Optionee is then deceased, be given to the Optionee’s personal representative if such representative has previously informed the Company of his status and address by written notice under this Section 5.3. Any notice shall have been deemed duly given when (i) delivered in person or (ii) enclosed in a properly addressed, sealed envelope or wrapper, deposited (with postage or fees prepaid) with a post office or branch post office regularly maintained by the United States Postal Service or an office regularly maintained by FedEx, UPS, or comparable non-public mail carrier.
Section 5.4Titles; Pronouns
Titles are provided herein for convenience only and are not to serve as a basis for interpretation or construction of this Agreement. The masculine pronoun shall include the feminine and neuter, and the singular the plural, where the context so indicates.
Section 5.5Applicability of Plan, Management Stockholder’s Agreement and Sale Participation Agreement
The Option and the Shares of Common Stock issued to the Optionee upon exercise of the Option shall be subject to all of the terms and provisions of the Plan, the Management Stockholder’s Agreement and a Sale Participation Agreement, to the extent applicable to the Option and such Shares.
Section 5.6Amendment
Subject to Section 10 of the Plan, this Agreement may be amended only by a writing executed by the parties hereto, which specifically states that it is amending this Agreement.
Section 5.7Governing Law
The laws of the State of Texas shall govern the interpretation, validity and performance of the terms of this Agreement regardless of the law that might be applied under principles of conflicts of laws.
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Section 5.8Arbitration
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 within the Dallas, Texas metropolitan area. 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. Each party shall bear its own legal fees and expenses, unless otherwise determined by the arbitrator.
[Signatures on next page.]
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IN WITNESS WHEREOF, this Agreement has been executed and delivered by the parties hereto.
| ENERGY FUTURE HOLDINGS CORP. | ||
| By: | /s/ Robert C. Walters | |
| Robert C. Walters | ||
| Executive Vice President | ||
| OPTIONEE: | ||
/s/ Charles Ray Enze | ||
| Charles Ray Enze | ||
A summary of Option grants governed by this Agreement appears on the following page.
[Signature Page of Stock Option Agreement]
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Summary of Option
| Original Time Option | Performance Option | Cliff Vesting Option | |||||||
Number of Shares subject to the Option | 800,000 | 160,000 | 640,000 | ||||||
Grant Date | May 20, 2008 | May 20, 2008 | December 1, 2009 | ||||||
Vesting Date | | 20% each year beginning on first anniversary of October 10, 2007 | | Fully vested February 25, 2009 | | 50% on September 30, 2012; 50% on | |||
Exercise Price | $ | 5.00 | $ | 5.00 | $ | 3.50 | |||
Number of vested Shares as of December 1, 2009 | 320,000 | 160,000 | None | ||||||
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Exhibit 12 (a)
ENERGY FUTURE HOLDINGS CORP.
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES,
AND RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERENCE DIVIDENDS
| Successor | Predecessor | |||||||||||||||||||||
| 2009 | 2008 | Period from October 11, 2007 Through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | 2006 | 2005 | |||||||||||||||||
EARNINGS: | ||||||||||||||||||||||
Income (loss) from continuing operations before extraordinary gain/(loss) and cumulative effect of changes in accounting principles | $ | 408 | $ | (9,998 | ) | $ | (1,361 | ) | $ | 699 | $ | 2,465 | $ | 1,775 | ||||||||
Add: Total federal income tax expense (benefit) | 367 | (471 | ) | (673 | ) | 309 | 1,263 | 632 | ||||||||||||||
Fixed charges (see detail below) | 3,225 | 5,280 | 905 | 777 | 907 | 856 | ||||||||||||||||
Preferred dividends of subsidiaries | — | — | — | — | — | 3 | ||||||||||||||||
Total earnings (loss) | $ | 4,000 | $ | (5,189 | ) | $ | (1,129 | ) | $ | 1,785 | $ | 4,635 | $ | 3,266 | ||||||||
FIXED CHARGES: | ||||||||||||||||||||||
Interest expense | $ | 3,190 | $ | 5,246 | $ | 899 | $ | 750 | $ | 877 | $ | 817 | ||||||||||
Rentals representative of the interest factor | 35 | 34 | 6 | 27 | 30 | 39 | ||||||||||||||||
Fixed charges deducted from earnings | 3,225 | 5,280 | 905 | 777 | 907 | 856 | ||||||||||||||||
Preferred dividends of subsidiaries (pretax) (a) | — | — | — | — | �� | — | 4 | |||||||||||||||
Total fixed charges | 3,225 | 5,280 | 905 | 777 | 907 | 860 | ||||||||||||||||
Preference dividends of registrant (pretax) (a) | — | — | — | — | — | 14 | ||||||||||||||||
Fixed charges and preference dividends | $ | 3,225 | $ | 5,280 | $ | 905 | $ | 777 | $ | 907 | $ | 874 | ||||||||||
RATIO OF EARNINGS TO FIXED CHARGES (b) | 1.24 | — | — | 2.30 | 5.11 | 3.80 | ||||||||||||||||
RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERENCE DIVIDENDS (b) | 1.24 | — | — | 2.30 | 5.11 | 3.74 | ||||||||||||||||
| (a) | Preferred/preference dividends multiplied by the ratio of pretax income to net income. |
| (b) | Fixed charges and combined fixed charges and preference dividends exceeded earnings by $10.469 billion and $2.034 billion for the year ended December 31, 2008 and for the period from October 11, 2007 through December 31, 2007, respectively. |
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Exhibit 18(a)
February 18, 2010
Energy Future Holdings Corp.
1601 Bryan Street
Dallas, Texas 75201
Dear Sirs/Madams:
We have audited the consolidated financial statements of Energy Future Holdings Corp. (“EFH Corp.”) as of December 31, 2009 and 2008 (successor), and for the years ended December 31, 2009 and 2008 (successor), the period from October 11, 2007 through December 31, 2007 (successor) and the period from January 1, 2007 through October 10, 2007 (predecessor), included in your Annual Report on Form 10-K to the Securities and Exchange Commission and have issued our report thereon dated February 18, 2010 (which report expresses an unqualified opinion and includes an explanatory paragraph related to EFH Corp. completing its merger with Texas Energy Future Merger Sub Corp and becoming a subsidiary of Texas Energy Future Holdings Limited Partnership on October 10, 2007). Note 1 to such financial statements contains a description of your change, during the year ended December 31, 2009, in the date for the annual goodwill impairment test for your reporting units. In our judgment, such change is to an alternative accounting principle that is preferable under the circumstances.
| Yours truly, |
| /s/ Deloitte & Touche LLP |
| Dallas, Texas |
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Exhibit 18(b)
February 18, 2010
Oncor Electric Delivery Holdings Company LLC
1601 Bryan Street
Dallas, Texas 75201
Dear Sirs/Madams:
We have audited the consolidated financial statements of Oncor Electric Delivery Holdings Company LLC and subsidiaries (“Oncor Holdings”) as of December 31, 2009 and 2008 (successor balance sheets), and for the years ended December 31, 2009 and 2008 (successor operations), the period from October 11, 2007 through December 31, 2007 (successor operations) and the period from January 1, 2007 through October 10, 2007 (predecessor operations) of Oncor Electric Delivery Company LLC (as Oncor Holdings’ predecessor) , included in Energy Future Holdings Corp.’s Annual Report on Form 10-K to the Securities and Exchange Commission and have issued our report thereon dated February 18, 2010 (which report expresses an unqualified opinion and includes an explanatory paragraph referring to Oncor Holdings as an indirect subsidiary of Energy Future Holdings Corp., which was merged with Texas Energy Future Merger Sub Corp and becoming a subsidiary of Texas Energy Future Holdings Limited Partnership on October 10, 2007). Note 1 to such financial statements contains a description of your change, during the year ended December 31, 2009, in the date for the annual goodwill impairment test for your reporting unit. In our judgment, such change is to an alternative accounting principle that is preferable under the circumstances.
| Yours truly, |
| /s/ Deloitte & Touche LLP |
| Dallas, Texas |
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EXHIBIT 21(a)
ENERGY FUTURE HOLDINGS CORP.
SUBSIDIARY HIERARCHY
Effective December 31, 2009
| 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 Trading Canada Limited | Canada | |
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 | |
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 | |
Wichita/Victory Avenue 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 Chilled Water Solutions Company | Texas | |
TXU SEM Company | Delaware | |
TXU Energy Retail Management Company LLC | Delaware |
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| Jurisdiction | ||
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 | |
Oncor Electric Delivery Transition Bond Company LLC | Delaware | |
Oncor License Holdings Company LLC | Texas | |
Oncor Communications Holdings Company LLC | Delaware | |
EFH Corporate Services Company | Texas | |
EFH CG Management Company LLC | Texas | |
EFH Communications Holdings Company LLC | Delaware | |
Generation Development Company LLC | Delaware | |
NCA Development Company LLC | Texas | |
EFH Industries Company LLC | Delaware | |
EFH Properties Company | Texas | |
Communications License Holdings I Inc. | Texas | |
EFH Investment Company | Texas | |
Basic Resources Inc. | Texas | |
TXU Receivables Company | Delaware | |
EFH CC Holdings Company LLC | Texas | |
EFH Vermont Insurance Company | Vermont | |
LSGT Gas Company LLC | Texas | |
LSGT Processing Company | Texas | |
Lone Star Energy Services, Inc | Texas | |
ENS Holdings I, Inc. | Texas | |
ENS Holdings II, Inc. | Texas | |
ENS Holdings Limited Partnership4 | Texas | |
LSGT SACROC, Inc.5 | Texas | |
LSGT Finance (II), Inc. | Texas | |
LSGT House Inc. | Texas | |
Enserch Finance N.V. | Netherlands Antilles | |
LSGT International Investments Limited | Delaware | |
Humphreys & Glasgow Limited | United Kingdom | |
EEC Holdings, Inc | Nevada | |
EECI, Inc. | Nevada | |
Ebasco Services of Canada, Ltd | Canada |
| 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. |
| 4 | 99% owned by ENS Holdings II, Inc. and 1% owned by ENS Holdings I, Inc. |
| 5 | 0.35% owned by ENS Holdings Limited Partnership and 99.65% owned by LSGT Finance (II), Inc. |
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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(s) 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(s) 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 18, 2010 | /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(s) 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(s) 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 18, 2010 | /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, 2009 (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 18th day of February 2010.
/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, 2009 (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 18th day of February 2010.
/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, 2009 | Year Ended December 31, 2008 | |||||||
| (millions of dollars) | ||||||||
| Net income (loss) attributable to EFH Corp. | $ | 344 | $ | (9,838 | ) | |||
| Income tax expense (benefit) | 367 | (471 | ) | |||||
| Interest expense and related charges | 2,912 | 4,935 | ||||||
| Depreciation and amortization | 1,754 | 1,610 | ||||||
| EBITDA | $ | 5,377 | $ | (3,764 | ) | |||
Oncor EBITDA | (1,354 | ) | (496 | ) | ||||
Oncor distributions/dividends (a) | 216 | 1,582 | ||||||
Interest income | (45 | ) | (27 | ) | ||||
Amortization of nuclear fuel | 95 | 76 | ||||||
Purchase accounting adjustments (b) | 346 | 460 | ||||||
Impairment of goodwill | 90 | 8,000 | ||||||
Impairment of assets and inventory write down (c) | 42 | 1,221 | ||||||
Net gain on debt exchange offers | (87 | ) | — | |||||
Net income (loss) attributable to noncontrolling interests | 64 | (160 | ) | |||||
EBITDA amount attributable to consolidated unrestricted subsidiaries | 3 | — | ||||||
Unrealized net (gain) loss resulting from hedging transactions | (1,225 | ) | (2,329 | ) | ||||
Amortization of “day one” net loss on Sandow 5 power purchase agreement | (10 | ) | — | |||||
Losses on sale of receivables | 12 | 29 | ||||||
Noncash compensation expenses (d) | 11 | 27 | ||||||
Severance expense (e) | 10 | 3 | ||||||
Transition and business optimization costs (f) | 22 | 45 | ||||||
Transaction and merger expenses (g) | 81 | 64 | ||||||
Insurance settlement proceeds (h) | — | (21 | ) | |||||
Restructuring and other (i) | (14 | ) | 35 | |||||
Expenses incurred to upgrade or expand a generation station (j) | 100 | 100 | ||||||
| Adjusted EBITDA per Incurrence Covenant | $ | 3,734 | $ | 4,845 | ||||
| Add back Oncor adjustments | $ | 1,123 | $ | (267 | ) | |||
| Adjusted EBITDA per Restricted Payments Covenants | $ | 4,857 | $ | 4,578 | ||||
| (a) | 2008 amount includes $1.253 billion distribution of net proceeds from the sale of Oncor noncontrolling interests. |
| (b) | Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits not recognized in net income due to purchase accounting. |
| (c) | Impairment of assets includes impairments of emission allowances and trade name intangible assets, impairments of land and the natural gas-fueled generation fleet and charges related to the cancelled development of coal-fueled generation facilities. |
| (d) | Noncash compensation expenses are accounted for under accounting standards related to stock compensation and exclude capitalized amounts. |
| (e) | Severance expense includes amounts incurred related to outsourcing, restructuring and other amounts deemed to be in excess of normal recurring amounts. |
| (f) | Transition and business optimization costs include professional fees primarily for retail billing and customer care systems enhancements and incentive compensation. |
| (g) | Transaction and merger expenses include costs related to the Merger and abandoned strategic transactions, outsourcing transition costs, administrative costs related to the cancelled program to develop coal-fueled generation facilities, the Sponsor Group management fee, costs related to certain growth initiatives and costs related to the Oncor sale of noncontrolling interests. |
| (h) | Insurance settlement proceeds include the amount received for property damage to certain mining equipment. |
| (i) | Restructuring and other for 2009 primarily represents reversal of certain liabilities accrued in purchase accounting and recorded as other income, partially offset by restructuring and nonrecurring activities; 2008 includes a litigation accrual, a charge related to the bankruptcy of a subsidiary of Lehman Brothers Holdings Inc., and other restructuring initiatives and nonrecurring activities. |
| (j) | Expenses incurred to upgrade or expand a generation station reflect noncapital outage costs. |
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Exhibit 99(c)
TCEH Consolidated
Adjusted EBITDA Reconciliation
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | |||||||
| (millions of dollars) | ||||||||
| Net income (loss) | $ | 709 | $ | (8,862 | ) | |||
| Income tax expense (benefit) | 447 | (411 | ) | |||||
| Interest expense and related charges | 1,833 | 3,918 | ||||||
| Depreciation and amortization | 1,172 | 1,092 | ||||||
| EBITDA | $ | 4,161 | $ | (4,263 | ) | |||
Interest income | (64 | ) | (60 | ) | ||||
Amortization of nuclear fuel | 95 | 76 | ||||||
Purchase accounting adjustments (a) | 299 | 413 | ||||||
Impairment of goodwill | 70 | 8,000 | ||||||
Impairment of assets and inventory write down (b) | 36 | 1,210 | ||||||
EBITDA amount attributable to consolidated unrestricted subsidiaries | 3 | — | ||||||
Unrealized net (gain) loss resulting from hedging transactions | (1,225 | ) | (2,329 | ) | ||||
Amortization of “day one” net loss on Sandow 5 power purchase agreement | (10 | ) | — | |||||
Corporate depreciation, interest and income tax expenses included in SG&A expense | 6 | — | ||||||
Losses on sale of receivables | 12 | 29 | ||||||
Noncash compensation expense (c) | 1 | 10 | ||||||
Severance expense (d) | 10 | 3 | ||||||
Transition and business optimization costs (e) | 25 | 33 | ||||||
Transaction and merger expenses (f) | 5 | 10 | ||||||
Insurance settlement proceeds (g) | — | (21 | ) | |||||
Restructuring and other (h) | (19 | ) | 31 | |||||
Expenses incurred to upgrade or expand a generation station (i) | 100 | 100 | ||||||
| Adjusted EBITDA per Incurrence Covenant | $ | 3,505 | $ | 3,242 | ||||
Expenses related to unplanned generation station outages (i) | 91 | 250 | ||||||
Other adjustments allowed to determine Adjusted EBITDA per Maintenance Covenant (j) | 38 | 15 | ||||||
| Adjusted EBITDA per Maintenance Covenant | $ | 3,634 | $ | 3,507 | ||||
| (a) | Purchase accounting adjustments include amortization of the intangible net asset value of retail and wholesale power sales agreements, environmental credits, coal purchase contracts, nuclear fuel contracts and power purchase agreements and the stepped up value of nuclear fuel. Also include certain credits not recognized in net income due to purchase accounting. |
| (b) | Impairment of assets includes impairments of emission allowances and trade name intangible assets and impairments of land and the natural gas-fueled generation fleet. |
| (c) | Noncash compensation expenses are accounted for under accounting standards related to stock compensation and exclude capitalized amounts. |
| (d) | Severance expense includes amounts incurred related to outsourcing, restructuring and other amounts deemed to be in excess of normal recurring amounts. |
| (e) | Transition and business optimization costs include professional fees primarily for retail billing and customer care systems enhancements and incentive compensation. |
| (f) | Transaction and merger expenses include costs related to the Merger, outsourcing transition costs and costs related to certain growth initiatives. |
| (g) | Insurance settlement proceeds include the amount received for property damage to certain mining equipment. |
| (h) | Restructuring and other for 2009 primarily represents reversal of certain liabilities accrued in purchase accounting and recorded as other income, partially offset by restructuring and nonrecurring activities; 2008 includes a charge related to the bankruptcy of a subsidiary of Lehman Brothers Holdings Inc. and other restructuring initiatives and nonrecurring activities. |
| (i) | Expenses incurred to upgrade or expand a generation station reflect noncapital outage costs. |
| (j) | Primarily pre-operating expenses relating to Oak Grove and Sandow 5. |
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Exhibit 99(d)
ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC
(SUCCESSOR) AND
ONCOR ELECTRIC DELIVERY COMPANY LLC (PREDECESSOR)
AN ENERGY FUTURE HOLDINGS CORP. ENTERPRISE
CONSOLIDATED FINANCIAL STATEMENTS
AS OF DECEMBER 31, 2009
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.
2008 Audited Financial Statements | Oncor Holdings’ audited financial statements for the year ended December 31, 2008 | |
| Capgemini | Capgemini Energy LP, a provider of business process support services to Oncor | |
| EBITDA | Refers to earnings (net income) before interest expense, income taxes, depreciation and amortization | |
| EFH Corp. | Refers to Energy Future Holdings Corp., a holding company, and/or its subsidiaries, depending on context. Its major subsidiaries include Oncor and TCEH. | |
| ERCOT | Electric Reliability Council of Texas, the independent system operator and the regional coordinator of the various electricity systems within Texas | |
| ERISA | Employee Retirement Income Security Act of 1974, as amended | |
| FASB | Financial Accounting Standards Board, the designated organization in the private sector for establishing standards for financial accounting and reporting | |
| FERC | US Federal Energy Regulatory Commission | |
| GAAP | generally accepted accounting principles | |
| Intermediate Holding | Refers to Energy Future Intermediate Holding Company LLC, a direct, wholly-owned subsidiary of EFH Corp. and the direct parent of Oncor Holdings. | |
| Investment LLC | Refers to Oncor Management Investment LLC, a limited liability company and noncontrolling interest owner of Oncor, whose managing member is Oncor and whose Class B Interests are owned by officers, directors and key employees of Oncor. | |
| IRS | US Internal Revenue Service | |
| kWh | kilowatt-hours | |
| LIBOR | London Interbank Offered Rate. An interest rate at which banks can borrow funds, in marketable size, from other banks in the London interbank market. | |
Limited Liability Company Agreement | The Second Amended and Restated Limited Liability Company Agreement of Oncor, dated as of November 5, 2008, by and among Oncor Holdings, Texas Transmission and Investment LLC, as amended. | |
| Luminant | Refers to subsidiaries of TCEH engaged in competitive market activities consisting of electricity generation and wholesale energy sales and purchases as well as commodity risk management and trading activities, all largely in Texas. | |
| Merger | The transaction referred to in “Merger Agreement” (defined immediately below) that was completed on October 10, 2007. | |
| Merger Agreement | Agreement and Plan of Merger, dated February 25, 2007, under which Texas Holdings agreed to acquire EFH Corp. | |
| Oncor | Refers to Oncor Electric Delivery Company LLC, a direct, majority-owned subsidiary of Oncor Holdings, and/or its wholly-owned consolidated bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC, depending on context. | |
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| Oncor Holdings | Refers to Oncor Electric Delivery Holdings Company LLC, a direct, wholly-owned subsidiary of Intermediate Holding and the direct majority owner of Oncor. | |
| Oncor Ring-Fenced Entities | Refers to Oncor Holdings and its direct and indirect subsidiaries | |
| OPEB | other postretirement employee benefits | |
| PUCT | Public Utility Commission of Texas | |
| PURA | Texas Public Utility Regulatory Act | |
| Purchase accounting | The purchase method of accounting for a business combination as prescribed by GAAP, whereby the cost or “purchase price” of a business combination, including the amount paid for the equity and direct transaction costs, are allocated to identifiable assets and liabilities (including intangible assets) based upon their fair values. The excess of the purchase price over the fair values of assets and liabilities is recorded as goodwill. | |
| REP | retail electric provider | |
| SARs | Stock Appreciation Rights | |
| SARs Plan | Refers to the Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan | |
| Sponsor Group | Collectively, the investment funds affiliated with Kohlberg Kravis Roberts & Co. L.P. (KKR), TPG Capital, L.P. and GS Capital Partners, an affiliate of Goldman Sachs & Co. (See Texas Holdings below.) | |
| TCEH | Refers to Texas Competitive Electric Holdings Company LLC, a direct, wholly-owned subsidiary of Energy Future Competitive Holdings Company and an indirect subsidiary of EFH Corp., and/or its subsidiaries, depending on context. | |
| Texas Holdings | Refers to Texas Energy Future Holdings Limited Partnership, a limited partnership controlled by the Sponsor Group that owns substantially all of the common stock of EFH Corp. | |
| Texas Holdings Group | Refers to Texas Holdings and its direct and indirect subsidiaries other than the Oncor Ring-Fenced Entities. | |
| Texas Transmission | Refers to Texas Transmission Investment LLC, a limited liability company that owns a 19.75% equity interest in Oncor. Texas Transmission is not affiliated with EFH Corp., any of EFH Corp.’s subsidiaries or any member of the Sponsor Group. | |
| TXU Energy | Refers to TXU Energy Retail Company LLC, a direct, wholly-owned subsidiary of TCEH engaged in the retail sale of electricity to residential and business customers. TXU Energy is a REP in competitive areas of ERCOT. | |
| US | United States of America | |
This Annual Report occasionally makes references to Oncor Holdings or Oncor when describing actions, rights or obligations of their respective subsidiaries. These references reflect the fact that the subsidiaries are consolidated with their respective parent companies for financial reporting purposes. However, these references should not be interpreted to imply that the parent company is actually undertaking the action or has the rights or obligations of the relevant subsidiary company or that the subsidiary company is undertaking an action or has the rights or obligations of its parent company or any other affiliate.
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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 (“Oncor Holdings” or the “Successor”) as of December 31, 2009 and 2008 (Successor balance sheets), and the related statements of consolidated income (loss), comprehensive income (loss), cash flows, and membership interests for the years ended December 31, 2009 and 2008 (Successor operations), and the period from October 11, 2007 through December 31, 2007 (Successor operations). We have also audited the accompanying statements of consolidated income (loss), comprehensive income (loss), cash flows, and shareholder’s equity of Oncor Electric Delivery Company LLC (the “Predecessor”) for the period from January 1, 2007 through October 10, 2007 (Predecessor operations). These financial statements are the responsibility of the Oncor Holdings’ management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Oncor Holdings is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Oncor Holdings’ internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the Successor’s consolidated financial statements referred to above present fairly, in all material respects, the financial position of Oncor Electric Delivery Holdings Company LLC and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for the years ended December 31, 2009 and 2008 and the period from October 11, 2007 through December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. Further, in our opinion, the Predecessor’s consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of Oncor Electric Delivery Company LLC for the period from January 1, 2007 through October 10, 2007 in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, Oncor Holdings is a wholly-owned subsidiary of Energy Future Holdings Corp., which was merged with Texas Energy Future Merger Sub Corp on October 10, 2007.
| /s/ Deloitte & Touche LLP |
| Dallas, Texas |
| February 18, 2010 |
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC (SUCCESSOR) AND
ONCOR ELECTRIC DELIVERY COMPANY LLC (PREDECESSOR)
STATEMENTS OF CONSOLIDATED INCOME (LOSS)
(millions of dollars)
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||
Operating revenues: | ||||||||||||||||
Affiliated | $ | 1,018 | $ | 1,000 | $ | 209 | $ | 823 | ||||||||
Nonaffiliated | 1,672 | 1,580 | 324 | 1,144 | ||||||||||||
Total operating revenues | 2,690 | 2,580 | 533 | 1,967 | ||||||||||||
Operating expenses: | ||||||||||||||||
Operation and maintenance | 962 | 852 | 200 | 649 | ||||||||||||
Write off of regulatory assets (Note 8) | 25 | — | — | — | ||||||||||||
Depreciation and amortization | 557 | 492 | 96 | 366 | ||||||||||||
Income taxes | 145 | 191 | 25 | 150 | ||||||||||||
Taxes other than income taxes | 385 | 391 | 87 | 305 | ||||||||||||
Total operating expenses | 2,074 | 1,926 | 408 | 1,470 | ||||||||||||
Operating income | 616 | 654 | 125 | 497 | ||||||||||||
Other income and deductions: | ||||||||||||||||
Impairment of goodwill (Note 3) | — | 860 | — | — | ||||||||||||
Other income (Note 20) | 49 | 45 | 11 | 3 | ||||||||||||
Other deductions (Note 20) | 14 | 25 | 8 | 30 | ||||||||||||
Nonoperating income taxes | 28 | 26 | 6 | 9 | ||||||||||||
Interest income | 43 | 45 | 12 | 44 | ||||||||||||
Interest expense and related charges (Note 20) | 346 | 316 | 70 | 242 | ||||||||||||
Net income (loss) | 320 | (483 | ) | 64 | 263 | |||||||||||
Net (income) loss attributable to noncontrolling interests | (64 | ) | 160 | — | — | |||||||||||
Net income (loss) attributable to Oncor Holdings | $ | 256 | $ | (323 | ) | $ | 64 | $ | 263 | |||||||
See Notes to Financial Statements.
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC (SUCCESSOR) AND
ONCOR ELECTRIC DELIVERY COMPANY LLC (PREDECESSOR)
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME (LOSS)
(millions of dollars)
| Successor | Predecessor | |||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||
Net income (loss) | $ | 320 | $ | (483 | ) | $ | 64 | $ | 263 | |||||||
Other comprehensive income, net of tax effects: | ||||||||||||||||
Cash flow hedges: | ||||||||||||||||
Net decrease in fair value of derivatives (net of tax benefit of —, $1, — and —) | — | (2 | ) | — | — | |||||||||||
Derivative value net losses related to hedged transactions recognized during the period in net income (net of tax expense of $— in all periods) | — | — | — | 1 | ||||||||||||
Comprehensive income (loss) | 320 | (485 | ) | 64 | 264 | |||||||||||
Comprehensive (income) loss attributable to noncontrolling interests | (64 | ) | 160 | — | — | |||||||||||
Comprehensive income (loss) attributable to Oncor Holdings | $ | 256 | $ | (325 | ) | $ | 64 | $ | 264 | |||||||
See Notes to Financial Statements.
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC (SUCCESSOR) AND
ONCOR ELECTRIC DELIVERY COMPANY LLC (PREDECESSOR)
STATEMENTS OF CONSOLIDATED CASH FLOWS
(millions of dollars)
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Cash flows — operating activities: | ||||||||||||||||||
Net income (loss) | $ | 320 | $ | (483 | ) | $ | 64 | $ | 263 | |||||||||
Adjustments to reconcile net income to cash provided by operating activities: | ||||||||||||||||||
Depreciation and amortization | 522 | 451 | 95 | 366 | ||||||||||||||
Write off of regulatory assets (Note 8) | 25 | — | — | — | ||||||||||||||
Deferred income taxes – net | 78 | 159 | 71 | 21 | ||||||||||||||
Amortization of investment tax credits | (5 | ) | (5 | ) | (1 | ) | (4 | ) | ||||||||||
Reversal of reserve recorded in purchase accounting (Note 13) | (10 | ) | — | — | — | |||||||||||||
Impairment of goodwill (Note 3) | — | 860 | — | — | ||||||||||||||
Bad debt expense | (3 | ) | 1 | (2 | ) | 2 | ||||||||||||
Stock-based incentive compensation expense | — | — | — | 3 | ||||||||||||||
Other, net | 2 | 5 | 3 | 1 | ||||||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||||
Accounts receivable – trade (including affiliates) | (29 | ) | (1 | ) | 39 | (47 | ) | |||||||||||
Impact of accounts receivable sales program (Note 9) | — | — | (113 | ) | 27 | |||||||||||||
Inventories | (29 | ) | (12 | ) | 6 | 19 | ||||||||||||
Accounts payable – trade (including affiliates) | 7 | 6 | (3 | ) | 8 | |||||||||||||
Deferred advanced metering system revenues (Note 8) | 57 | — | — | — | ||||||||||||||
Other – assets | (40 | ) | (141 | ) | (32 | ) | (24 | ) | ||||||||||
Other – liabilities | 55 | (11 | ) | (62 | ) | 47 | ||||||||||||
Cash provided by operating activities | 950 | 829 | 65 | 682 | ||||||||||||||
Cash flows — financing activities: | ||||||||||||||||||
Issuance of long-term debt | — | 1,500 | — | 800 | ||||||||||||||
Repayments of long-term debt | (104 | ) | (99 | ) | (832 | ) | (264 | ) | ||||||||||
Net increase (decrease) in short-term borrowings | 279 | (943 | ) | 895 | (288 | ) | ||||||||||||
Proceeds from sale of noncontrolling interests, net of transaction costs (Note 14) | — | 1,253 | — | — | ||||||||||||||
Distribution to parent of equity sale net proceeds | — | (1,253 | ) | — | — | |||||||||||||
Distributions/dividends to parent | (216 | ) | (330 | ) | — | (326 | ) | |||||||||||
Distributions to noncontrolling interests | (56 | ) | — | — | — | |||||||||||||
Net decrease in advances from parent | — | — | — | (24 | ) | |||||||||||||
Decrease in income tax-related note receivable from TCEH | 35 | 34 | 9 | 24 | ||||||||||||||
Excess tax benefit on stock-based incentive compensation | — | 10 | 15 | — | ||||||||||||||
Debt discount, financing and reacquisition expenses – net | (3 | ) | (18 | ) | (1 | ) | (10 | ) | ||||||||||
Cash provided by (used in) financing activities | (65 | ) | 154 | 86 | (88 | ) | ||||||||||||
Cash flows — investing activities: | ||||||||||||||||||
Capital expenditures | (998 | ) | (919 | ) | (162 | ) | (580 | ) | ||||||||||
Cash settlements related to outsourcing contract termination (Note 16) | — | 20 | — | — | ||||||||||||||
Other | 16 | 20 | 16 | 2 | ||||||||||||||
Cash used in investing activities | (982 | ) | (879 | ) | (146 | ) | (578 | ) | ||||||||||
Net change in cash and cash equivalents | (97 | ) | 104 | 5 | 16 | |||||||||||||
Cash and cash equivalents — beginning balance | 126 | 22 | 17 | 1 | ||||||||||||||
Cash and cash equivalents — ending balance | $ | 29 | $ | 126 | $ | 22 | $ | 17 | ||||||||||
See Notes to Financial Statements.
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC (SUCCESSOR)
CONSOLIDATED BALANCE SHEETS
(millions of dollars)
| Successor | ||||||
| December 31, 2009 | December 31, 2008 | |||||
| ASSETS | ||||||
Current assets: | ||||||
Cash and cash equivalents | $ | 29 | $ | 126 | ||
Restricted cash (Note 15) | 47 | 51 | ||||
Trade accounts receivable from nonaffiliates — net (Note 9) | 243 | 217 | ||||
Trade accounts and other receivables from affiliates | 188 | 182 | ||||
Income taxes receivable from EFH Corp. (Note 19) | — | 22 | ||||
Materials and supplies inventories — at average cost | 92 | 63 | ||||
Accumulated deferred income taxes (Note 7) | 10 | 54 | ||||
Prepayments | 76 | 75 | ||||
Other current assets | 8 | 9 | ||||
Total current assets | 693 | 799 | ||||
Restricted cash (Note 15) | 14 | 16 | ||||
Investments and other property (Note 15) | 72 | 72 | ||||
Property, plant and equipment — net (Note 20) | 9,174 | 8,606 | ||||
Goodwill (Note 20) | 4,064 | 4,064 | ||||
Note receivable due from TCEH (Note 19) | 217 | 254 | ||||
Regulatory assets — net (Note 8) | 1,959 | 1,892 | ||||
Other noncurrent assets | 51 | 60 | ||||
Total assets | $ | 16,244 | $ | 15,763 | ||
| LIABILITIES AND MEMBERSHIP INTERESTS | ||||||
Current liabilities: | ||||||
Short-term borrowings (Note 10) | $ | 616 | $ | 337 | ||
Long-term debt due currently (Note 11) | 108 | 103 | ||||
Trade accounts payable | 129 | 124 | ||||
Income taxes payable to EFH Corp. (Note 19) | 5 | — | ||||
Accrued taxes other than income taxes | 137 | 141 | ||||
Accrued interest | 104 | 103 | ||||
Other current liabilities | 106 | 99 | ||||
Total current liabilities | 1,205 | 907 | ||||
Accumulated deferred income taxes (Notes 1 and 7) | 1,369 | 1,333 | ||||
Investment tax credits | 37 | 42 | ||||
Long-term debt, less amounts due currently (Note 11) | 4,996 | 5,101 | ||||
Other noncurrent liabilities and deferred credits (Note 20) | 1,879 | 1,720 | ||||
Total liabilities | 9,486 | 9,103 | ||||
Commitments and contingencies (Note 12) | ||||||
Membership interests (Note 13): | ||||||
Oncor Holdings membership interest | 5,395 | 5,305 | ||||
Noncontrolling interests in subsidiary | 1,363 | 1,355 | ||||
Total membership interests | 6,758 | 6,660 | ||||
Total liabilities and membership interests | $ | 16,244 | $ | 15,763 | ||
See Notes to Financial Statements.
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC (SUCCESSOR)
STATEMENTS OF CONSOLIDATED MEMBERSHIP INTERESTS
(millions of dollars)
| Successor | |||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | |||||||||
Capital account: | |||||||||||
Balance at beginning of period (a) | $ | 5,307 | $ | 7,643 | $ | 7,539 | |||||
Net income (loss) attributable to Oncor Holdings | 256 | (323 | ) | 64 | |||||||
Distributions paid to parent | (216 | ) | (1,583 | ) | — | ||||||
Capital contributions (b) | 50 | — | — | ||||||||
Effect of sale of noncontrolling interests (Notes 13 and 14) | — | (406 | ) | — | |||||||
Distribution of investment in Oncor Communications Holding Company LLC to parent | — | (24 | ) | — | |||||||
Investment by Texas Holdings | — | — | 12 | ||||||||
Settlement of incentive compensation plans | — | — | 28 | ||||||||
Balance at end of period | 5,397 | 5,307 | 7,643 | ||||||||
Accumulated other comprehensive income (loss), net of tax effects: | |||||||||||
Balance at beginning of period | (2 | ) | — | — | |||||||
Net effects of cash flow hedges | — | (2 | ) | — | |||||||
Balance at end of period | (2 | ) | (2 | ) | — | ||||||
Oncor Holdings membership interest at end of period | 5,395 | 5,305 | 7,643 | ||||||||
Noncontrolling interests in subsidiary (Note 14): | |||||||||||
Balance at beginning of period | 1,355 | — | — | ||||||||
Net income (loss) attributable to noncontrolling interests | 64 | (160 | ) | — | |||||||
Distributions to noncontrolling interests | (56 | ) | (2 | ) | — | ||||||
Investment | — | 1,253 | — | ||||||||
Effect of sale of noncontrolling interests (Note 14) | — | 265 | — | ||||||||
Other | — | (1 | ) | — | |||||||
Noncontrolling interests in subsidiary at end of period | 1,363 | 1,355 | — | ||||||||
Total membership interests at end of period | $ | 6,758 | $ | 6,660 | $ | 7,643 | |||||
| (a) | The beginning equity balance for the period from October 11, 2007 through December 31, 2007 reflects the application of push-down accounting as a result of the Merger. |
| (b) | Reflects noncash settlement of certain income taxes payable arising as a result of the sale of noncontrolling interests in Oncor. |
See Notes to Financial Statements.
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ONCOR ELECTRIC DELIVERY COMPANY LLC (PREDECESSOR)
STATEMENT OF CONSOLIDATED SHAREHOLDER’S EQUITY
(millions of dollars)
| Predecessor | ||||
| Period from January 1, 2007 through October 10, 2007 | ||||
Common stock without par value (number of authorized shares — 100,000,000): | ||||
Balance at beginning of period | $ | 1,986 | ||
Effects of stock-based incentive compensation plans (Note 13) | 18 | |||
Balance at end of period (number of shares outstanding October 10, 2007 — 0) | 2,004 | |||
Retained earnings: | ||||
Balance at beginning of period | 1,008 | |||
Net income | 263 | |||
Dividends to parent | (326 | ) | ||
Effect of adoption of accounting guidance related to uncertain tax positions (Note 6) | (9 | ) | ||
Other | 1 | |||
Balance at end of period | 937 | |||
Accumulated other comprehensive income (loss), net of tax effects: | ||||
Balance at beginning of period | (19 | ) | ||
Net effects of cash flow hedges | 1 | |||
Balance at end of period | (18 | ) | ||
Total shareholder’s equity at end of period | $ | 2,923 | ||
See Notes to Financial Statements.
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC (SUCCESSOR) AND
ONCOR ELECTRIC DELIVERY COMPANY LLC (PREDECESSOR)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
| 1. | SIGNIFICANT ACCOUNTING POLICIES |
Description of Business
Oncor Holdings is a Dallas, Texas-based holding company whose financial statements reflect almost entirely the operations of its direct, majority (approximately 80%) owned subsidiary, Oncor. Oncor is a regulated electricity transmission and distribution company principally engaged in providing delivery services to REPs, including subsidiaries of TCEH, that sell power in the north-central, eastern and western parts of Texas. Distribution revenues from TCEH represented 38% and 39% of total revenues for the years ended December 31, 2009 and 2008, respectively. Oncor Holdings is a direct, wholly-owned subsidiary of Intermediate Holding, a direct, wholly-owned subsidiary of EFH Corp. With the closing of the Merger on October 10, 2007, EFH Corp. became a subsidiary of Texas Holdings, which is controlled by the Sponsor Group (see Note 2), and Oncor Holdings and Intermediate Holding were formed. See “Glossary” for definition of terms and abbreviations, including the Merger. References in this report to Oncor Holdings are to Oncor Holdings and/or its direct or indirect subsidiaries as apparent in the context. Oncor Holdings’ financial statements reflect almost entirely the operations of Oncor; consequently, there are no separate reportable business segments.
Oncor Holdings’ consolidated financial statements include its indirect, bankruptcy-remote financing subsidiary, Oncor Electric Delivery Transition Bond Company LLC. This financing subsidiary was organized for the limited purpose of issuing specified transition bonds in 2003 and 2004. Oncor Electric Delivery Transition Bond Company LLC issued $1.3 billion principal amount of securitization (transition) bonds to recover generation-related regulatory asset stranded costs and other qualified costs under an order issued by the PUCT in 2002.
Various “ring-fencing” measures have been taken to enhance the credit quality of Oncor Holdings and Oncor. These measures serve to mitigate Oncor’s and Oncor Holdings’ credit exposure to the Texas Holdings Group and to reduce the risk that the assets and liabilities of Oncor or Oncor Holdings would be substantively consolidated with the assets and liabilities of the Texas Holdings Group in the event of a bankruptcy of one or more of those entities. Such measures include, among other things: Oncor’s sale of a 19.75% equity interest to Texas Transmission in November 2008; maintenance of separate books and records for the Oncor Ring-Fenced Entities; the board of directors of Oncor Holdings and Oncor being comprised of a majority of independent directors, and prohibitions on the Oncor Ring-Fenced Entities’ providing credit support to, or receiving credit support from, any member of the Texas Holdings Group. The assets and liabilities of the Oncor Ring-Fenced Entities are separate and distinct from those of the Texas Holdings Group, including TXU Energy and Luminant, and none of the assets of the Oncor Ring-Fenced Entities are available to satisfy the debt or other obligations of any member of the Texas Holdings Group. Oncor and Oncor Holdings do not bear any liability for obligations of the Texas Holdings Group (including, but not limited to, debt obligations), and vice versa. Accordingly, Oncor Holdings’ operations are conducted, and its cash flows managed, independently from the Texas Holdings Group.
See Note 14 for discussion of noncontrolling interests sold by Oncor in November 2008.
Basis of Presentation
The consolidated financial statements of Oncor Holdings have been prepared in accordance with US GAAP. The accompanying consolidated statements of income (loss), comprehensive income (loss), cash flows and membership interests/shareholder’s equity present results of operations and cash flows of Oncor Holdings for periods subsequent to the Merger (Successor) and of Oncor for periods preceding the Merger (Predecessor), since Oncor Holdings did not exist prior to the Merger. The consolidated financial statements have been prepared on the same basis as the 2008 Audited Financial Statements. The consolidated financial statements of the Successor reflect the application of purchase accounting in accordance with the provisions of accounting standards related to business combinations. All intercompany items and transactions have been eliminated in consolidation. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated. Subsequent events have been evaluated through February 18, 2010, the date these consolidated financial statements were issued.
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Income Taxes
EFH Corp. files a consolidated federal income tax return. Prior to 2007, federal income taxes were allocated to subsidiaries, including Oncor Holdings and Oncor, based on their respective taxable income or loss. Effective with the November 2008 sale of equity interests in Oncor (see Note 14), Oncor became a partnership for US federal income tax purposes, and subsequently EFH Corp.’s share of partnership income is included in its consolidated federal income tax return. In connection with the Merger, Oncor, Oncor Holdings and EFH Corp. entered into a tax sharing agreement (amended in November 2008 to include Texas Transmission and Investment LLC) that is retroactive to January 1, 2007. The tax sharing agreement provides for the calculation of tax liability for each of Oncor Holdings and Oncor substantially as if these entities file their own income tax returns and requires tax payments to their members determined on that basis (without duplication for any income taxes paid by a subsidiary of Oncor Holdings). Deferred income taxes are provided for temporary differences between the book and tax bases of assets and liabilities of Oncor Holdings, which primarily relate to the difference between the book and tax basis of the investment in Oncor.
Amounts of deferred income tax assets and liabilities, as well as current and noncurrent accruals, are determined in accordance with the provisions of accounting guidance for income taxes and for uncertainty in income taxes. See Note 7 for additional detail.
Use of Estimates
Preparation of Oncor Holdings’ financial statements requires management to make estimates and assumptions about future events that affect the reporting of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense, including fair value measurements. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments, other than those disclosed elsewhere herein, were made to previous estimates or assumptions during the current year.
Purchase Accounting
The Merger was accounted for under purchase accounting, whereby the total purchase price of the transaction was allocated to EFH Corp.’s identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values, and the excess of the purchase price over the fair value of net assets acquired was recorded as goodwill. The allocation resulted in a significant amount of goodwill, a portion of which was assigned to Oncor Holdings. See Note 2 for details regarding the effect of purchase accounting.
Derivative Instruments and Mark-to-Market Accounting
Oncor has from time-to-time entered into derivative instruments, referred to as interest rate swaps, to hedge interest rate risk. If the instrument meets the definition of a derivative under accounting standards related to derivative instruments and hedging activities, the fair value of each derivative is required to be recognized on the balance sheet as a derivative asset or liability and changes in the fair value recognized in net income, unless criteria for certain exceptions are met. This recognition is referred to as “mark-to-market” accounting.
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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 with an adjustment for the impact of weather and other factors on unmetered deliveries (unbilled revenue).
Impairment of Goodwill and Other Intangible Assets
Oncor Holdings evaluates goodwill for impairment at least annually. The impairment tests performed are based on determinations of enterprise value using discounted cash flow analyses, comparable company equity values and any relevant transactions indicative of enterprise values. See Note 20 for details of goodwill and other intangible assets and Note 3 for discussion of a goodwill impairment charge recorded in 2008.
In 2009, Oncor Holdings changed the annual test date from October 1 to December 1. Management determined the new annual goodwill test date is preferable because of efficiencies gained by aligning the test with Oncor Holdings’ annual budget and five-year plan processes in the fourth quarter. The change in the annual test date did not delay, accelerate or avoid an impairment charge, and retrospective application of this change in accounting principle did not affect previously reported results.
System of Accounts
The accounting records of Oncor Holdings have been maintained in accordance with the FERC Uniform System of Accounts as adopted by the PUCT.
Defined Benefit Pension Plans and Other Postretirement Employee Benefit (OPEB) Plans
Oncor participates in an EFH Corp. pension plan that offers benefits based on either a traditional defined benefit formula or a cash balance formula and an OPEB plan that offers certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from Oncor. Costs of pension and OPEB plans are dependent upon numerous factors, assumptions and estimates. See Note 17 for additional information regarding pension and OPEB plans.
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Stock-Based Incentive Compensation
Prior to the Merger, EFH Corp. provided discretionary awards payable in its common stock to qualified managerial employees of Oncor under EFH Corp.’s shareholder-approved long-term incentive plans. Oncor Holdings recognized expense for these awards over the vesting period based on the grant-date fair value of those awards. In November 2008, Oncor implemented the SARs Plan for certain management that purchased equity interests in Oncor indirectly by investing in Investment LLC. SARs have been awarded under the SARs Plan and are being accounted for based upon the provisions of guidance for share-based payment. See Note 18 for information regarding stock-based compensation, including SARs granted to certain members of Oncor’s board of directors.
Fair Value of Nonderivative Financial Instruments
The carrying amounts for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value due to the short maturity of such instruments. The fair values of other financial instruments, for which carrying amounts and fair values have not been presented, are not materially different than their related carrying amounts.
Franchise Taxes
Franchise taxes are assessed to Oncor by local governmental bodies, based on kWh delivered and are the principal component of “taxes other than income taxes” as reported in the income statement. Franchise taxes are not a “pass through” item. Rates charged to customers by Oncor are intended to recover the franchise taxes, but Oncor is not acting as an agent to collect the taxes from customers.
Cash and Cash Equivalents
For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered to be cash equivalents. See Note 15 for details regarding restricted cash.
Property, Plant and Equipment
Properties are stated at original cost. The cost of self-constructed property additions includes materials and both direct and indirect labor and applicable overhead and an allowance for funds used during construction.
Depreciation of property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties based on depreciation rates approved by the PUCT. Depreciation rates include plant removal costs as a component of depreciation expense, consistent with regulatory treatment. As is common in the industry, depreciation expense is recorded using composite depreciation rates that reflect blended estimates of the lives of major asset groups as compared to depreciation expense calculated on a component asset-by-asset basis.
In accordance with the PUCT’s August 2009 order in Oncor’s rate review, the remaining net book value and anticipated removal cost of existing meters that are being replaced by advanced meters is being charged (amortized) to expense over an 11-year cost recovery period.
Allowance For Funds Used During Construction (AFUDC)
AFUDC is a regulatory cost accounting procedure whereby both interest charges on borrowed funds and a return on equity capital used to finance construction are included in the recorded cost of utility plant and equipment being constructed. AFUDC is capitalized on all projects involving construction periods lasting greater than thirty days. The equity portion of capitalized AFUDC is accounted for as other income. There was no equity AFUDC for the periods presented. See Note 20 for detail of amounts charged to interest expense.
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Regulatory Assets and Liabilities
The financial statements of Oncor Holdings reflect regulatory assets and liabilities under cost-based rate regulation in accordance with accounting standards related to the effect of certain types of regulation. The assumptions and judgments used by regulatory authorities continue to have an impact on the recovery of costs, the rate earned on invested capital and the timing and amount of assets to be recovered by rates. See Note 8 for details of regulatory assets and liabilities.
Sale of Noncontrolling Interests
See Note 14 for discussion of accounting for the sale of noncontrolling interests by Oncor.
Changes in Accounting Standards
In June 2009, the FASB issued “TheFASB Accounting Standards Codification™ and the Hierarchy of Generally Accepted Accounting Principles,” which establishes theFASB Accounting Standards Codification™ (Codification) as the source of authoritative US GAAP recognized by the FASB to be applied to nongovernmental entities. The Codification was effective for financial statements issued for interim and annual periods ending after September 15, 2009. The adoption of the Codification did not affect reported results of operations, financial condition or cash flows.
In May 2009, the FASB issued new guidance related to subsequent events that requires disclosure of the date through which Oncor Holdings has evaluated subsequent events related to the financial statements being issued and the basis for that date. The adoption of this guidance as of April 1, 2009 did not affect reported results of operations, financial condition or cash flows, and the required disclosure is provided above in “Basis of Presentation.”
| 2. | FINANCIAL STATEMENT EFFECTS OF THE MERGER |
EFH Corp. accounted for the Merger under purchase accounting in accordance with the provisions of accounting standards related to business combinations, whereby the total purchase price of the transaction was allocated to EFH Corp.’s identifiable tangible and intangible assets acquired and liabilities assumed based on their fair values as of the Merger date. As a result of cost-based regulatory rate-setting processes, the book value of the majority of Oncor’s assets and liabilities effectively represents fair value, and no adjustments to the carrying value of those regulated assets or liabilities were recorded. The excess of the purchase price over the fair value of net assets acquired was recorded as goodwill. The purchase price was allocated to TCEH and Oncor. The purchase price amount assigned to Oncor was based on the relative enterprise value of the business on the closing date of the Merger and resulted in an excess of purchase price over fair value of assets and liabilities of $4.9 billion, which was recorded as goodwill. See Note 20 for disclosures related to goodwill and Note 3 regarding an impairment charge recorded in the fourth quarter of 2008.
The following table summarizes the final purchase price allocation to the estimated fair values of the assets acquired and liabilities assumed (billions of dollars):
Purchase price assigned to Oncor | $ | 7.6 | |||
Property, plant and equipment | 7.9 | ||||
Regulatory assets – net | 1.3 | ||||
Other assets | 1.3 | ||||
Total assets acquired | 10.5 | ||||
Short-term borrowings and long-term debt | 5.1 | ||||
Deferred income tax liabilities | 1.3 | ||||
Other liabilities | 1.4 | ||||
Total liabilities assumed | 7.8 | ||||
Net identifiable assets acquired | 2.7 | ||||
Goodwill | $ | 4.9 | |||
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As part of purchase accounting, the carrying value of certain generation-related regulatory assets securitized by transition bonds, which have been reviewed and approved by the PUCT for recovery but without earning a rate of return, was reduced by $213 million. This amount will be accreted to other income over the recovery period remaining as of the closing date of the Merger (approximately nine years). The related securitization (transition) bonds were also fair valued and the resulting discount of $12 million will be amortized to interest expense over the life of the bonds remaining as of the closing date of the Merger (approximately nine years).
The final purchase price allocation includes $16 million in liabilities recorded in connection with the notice of termination of outsourcing arrangements with Capgemini under the change of control provisions of such arrangements (also see Note 16). Oncor incurred $4 million of these exit liabilities during the year ended December 31, 2009. In December 2009, Oncor recorded a $10 million reversal of a portion of these exit liabilities due primarily to a shorter than expected outsourcing services transition period, and this reversal is reflected in other income (see Note 19). The remaining accrual totaling $2 million is expected to be settled in 2010.
| 3. | GOODWILL IMPAIRMENT |
The 2009 annual goodwill impairment testing performed as of October 1 and December 1, 2009 in accordance with accounting guidance for a change in annual impairment testing dates resulted in no impairment (see discussion in Note 1 regarding change in the annual test date from October 1 to December 1). The testing determined that Oncor Holdings’ estimated fair value (enterprise value) exceeded its carrying value by approximately 10%, resulting in no additional testing being required and no impairment. Key assumptions in the valuation include discount rates, growth of the rate base and return on equity allowed by the regulatory authority.
In the fourth quarter of 2008, Oncor Holdings recorded a goodwill impairment charge totaling $860 million, which is not deductible for income tax-related purposes.
Although the annual goodwill impairment test date set by management was October 1, management determined that in consideration of the continuing deterioration of securities values during the fourth quarter of 2008, an impairment testing trigger occurred subsequent to that test date; consequently, the impairment charge was based on estimated fair values at December 31, 2008. The fair value calculation was completed in the first quarter of 2009 with no additional impairment charge.
The impairment determination involved significant assumptions and judgments in estimating enterprise values and the fair values of assets and liabilities. The impairment primarily arose from the dislocation in the capital markets that increased interest rate spreads and the resulting discount rates used in estimating fair values and the effect of declines in market values of debt and equity securities of comparable companies.
The calculations supporting the impairment determination utilized models that took into consideration multiple inputs, including debt yields, equity prices of comparable companies and other inputs. These models were generally used in developing long-term forward discount rates for determining enterprise value and fair values of certain individual assets and liabilities. The fair value measurements resulting from such models are classified as Level 3 non-recurring fair value measurements consistent with accounting standards related to the determination of fair value.
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| 4. | STIPULATION APPROVED BY THE PUCT |
Oncor and Texas Holdings agreed to the terms of a stipulation, which was conditional upon completion of the Merger, with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. In February 2008, the PUCT entered an order approving the stipulation. The PUCT issued a final order on rehearing in April 2008 that has been appealed to the 200th District Court of Travis County, Texas. The parties to the appeal have agreed to a schedule that would result in a hearing in June 2010.
In addition to commitments Oncor made in its filings in the PUCT review, the stipulation included the following provisions, among others:
| • | Oncor provided a one-time $72 million refund to its REP customers in the September 2008 billing cycle. The refund was in the form of a credit on distribution fee billings. The liability for the refund was recorded as part of purchase accounting. |
| • | Consistent with the 2006 cities rate settlement (see Note 5), Oncor filed a system-wide rate case in June 2008 based on a test-year ended December 31, 2007. In August 2009, the PUCT issued a final order on this rate case. See Note 8. |
| • | Oncor agreed not to request recovery of approximately $56 million of regulatory assets related to self-insurance reserve costs and 2002 restructuring expenses. These regulatory assets were eliminated as part of purchase accounting. |
| • | The dividends paid by Oncor will be limited through December 31, 2012, to an amount not to exceed Oncor’s net income (determined in accordance with GAAP, subject to certain defined adjustments) for the period beginning October 11, 2007 and ending December 31, 2012, and are further limited by an agreement that Oncor’s regulatory capital structure, as determined by the PUCT, will be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. |
| • | Oncor committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. |
| • | Oncor committed to an additional $100 million in spending over the five-year period ending December 31, 2012 on demand-side management or other energy efficiency initiatives. These additional expenditures will not be recoverable in rates, and this amount was recorded as a regulatory liability as part of purchase accounting and consistent with accounting standards related to the effect of certain types of regulation. |
| • | If Oncor’s credit rating is below investment grade with two or more rating agencies, TCEH will post a letter of credit in an amount of $170 million to secure TXU Energy’s payment obligations to Oncor. |
| • | Oncor agreed not to request recovery of the $4.9 billion of goodwill resulting from purchase accounting or any future impairment of the goodwill in its rates. |
| 5. | CITIES RATE SETTLEMENT IN 2006 |
In January 2006, Oncor agreed with a steering committee representing 108 cities in Texas (Cities) to defer the filing of a system-wide rate case with the PUCT to no later than July 1, 2008 (based on a test year ending December 31, 2007). Oncor filed the rate case with the PUCT in June 2008, and the PUCT issued a final order on the case in 2009. Oncor extended the benefits of the agreement to 292 nonlitigant cities. The agreements provided that Oncor would make payments to participating cities totaling approximately $70 million, including incremental franchise taxes.
This amount was recognized in earnings over the period from May 2006 through June 2008. Amounts recognized totaled $11 million in 2009, $23 million in 2008, $8 million for the period October 11, 2007 through December 31, 2007 and $25 million for the period January 1, 2007 through October 10, 2007, of which $2 million, $13 million, $6 million and $20 million, respectively, is reported in other deductions (see Note 20), and the remainder as taxes other than income taxes. Amounts recognized in 2009 represented extension of benefits per the agreement as a result of the timing of completion of the rate case.
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| 6. | ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES |
Effective January 1, 2007, EFH Corp. and its subsidiaries adopted accounting guidance related to uncertain tax positions. This guidance requires that each tax position be reviewed and assessed with recognition and measurement of the tax benefit based on a “more-likely-than-not” standard with respect to the ultimate outcome, regardless of whether this assessment is favorable or unfavorable. Oncor Holdings applied updated guidance to determine if each tax position was effectively settled for the purpose of recognizing previously uncertain tax positions. Oncor Holdings completed its review and assessment of uncertain tax positions and in 2007 recorded a net charge to retained earnings and an increase to noncurrent liabilities of $9 million in accordance with the new accounting rule.
EFH Corp. and its subsidiaries file income tax returns in US federal, state and foreign jurisdictions and are subject to examinations by the IRS and other taxing authorities. Examinations of EFH Corp. and its subsidiaries’ income tax returns for the years ending prior to January 1, 2003 are complete, but the tax years 1997 through 2002 remain in appeals with the IRS. In 2008, EFH Corp. was notified of the commencement of an IRS audit of tax years 2003 to 2006. The audit is expected to require two years to complete. Texas franchise and margin tax returns are under examination or still open for examination for tax years beginning after 2002. Prior to the 2007 Merger, Oncor was a member of EFH Corp.’s consolidated group federal income tax returns.
Oncor Holdings classifies interest and penalties expense related to uncertain tax positions as current income tax expense. Amounts recorded related to interest and penalties totaled a benefit of $5 million in the year ended December 31, 2009 and expenses of $6 million (including $2 million recorded as goodwill) in the year ended December 31, 2008, $2 million for the period October 11, 2007 through December 31, 2007 and $3 million for the period January 1, 2007 through October 10, 2007 (all amounts after tax).
Noncurrent liabilities included a total of $20 million and $22 million in accrued interest at December 31, 2009 and 2008, respectively. Effective in 2009, the federal income tax benefit on the interest accrued on uncertain tax positions is recorded as accumulated deferred income taxes. Such amounts were previously reported net as a reduction of the liability for uncertain tax positions.
The following table summarizes the changes to the uncertain tax positions, reported in other noncurrent liabilities in the consolidated balance sheet, during the years ended December 31, 2009 and 2008:
| 2009 | 2008 | |||||||
Balance at January 1, excluding interest and penalties | $ | 122 | $ | 111 | ||||
Additions based on tax positions related to prior years | 22 | 41 | ||||||
Reductions based on tax positions related to prior years | (73 | ) | (30 | ) | ||||
Additions based on tax positions related to the current year | — | — | ||||||
Balance at December 31, excluding interest and penalties | $ | 71 | $ | 122 | ||||
Of the balance at December 31, 2009, $60 million represents tax positions for which the uncertainty relates to the timing of recognition for tax purposes. The disallowance of such positions would not affect the effective tax rate, but would accelerate the payment of cash under the tax sharing agreement to an earlier period.
With respect to tax positions for which the ultimate deductibility is uncertain (permanent items), should EFH Corp. or Oncor Holdings sustain such positions on income tax returns previously filed, Oncor Holdings’ liabilities recorded would be reduced by $11 million, resulting in increased net income and a favorable impact on the effective tax rate.
Oncor Holdings does not expect the total amount of liabilities recorded related to uncertain tax positions will significantly increase or decrease within the next 12 months.
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| 7. | INCOME TAXES |
The components of Oncor Holdings’ income tax expense are as follows:
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Reported in operating expenses: | ||||||||||||||||||
Current: | ||||||||||||||||||
US federal | $ | 69 | $ | 37 | $ | (46 | ) | $ | 116 | |||||||||
State | 17 | 17 | — | 12 | ||||||||||||||
Deferred: | ||||||||||||||||||
US federal | 67 | 142 | 74 | 26 | ||||||||||||||
State | (3 | ) | — | (2 | ) | — | ||||||||||||
Amortization of investment tax credits | (5 | ) | (5 | ) | (1 | ) | (4 | ) | ||||||||||
Total | 145 | 191 | 25 | 150 | ||||||||||||||
Reported in other income and deductions: | ||||||||||||||||||
Current: | ||||||||||||||||||
US federal | 13 | 8 | 7 | 8 | ||||||||||||||
State | 1 | 1 | — | 1 | ||||||||||||||
Deferred federal | 14 | 17 | (1 | ) | — | |||||||||||||
Total deferred | 28 | 26 | 6 | 9 | ||||||||||||||
Total income tax expense | $ | 173 | $ | 217 | $ | 31 | $ | 159 | ||||||||||
Reconciliation of income taxes computed at the US federal statutory rate to income tax expense:
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Income (loss) before income taxes | $ | 493 | $ | (266 | ) | $ | 95 | $ | 422 | |||||||||
Income taxes at the US federal statutory rate of 35% | $ | 173 | $ | (93 | ) | $ | 33 | $ | 148 | |||||||||
Goodwill impairment | — | 301 | — | — | ||||||||||||||
Amortization of investment tax credits – net of deferred tax effect | (5 | ) | (5 | ) | (1 | ) | (4 | ) | ||||||||||
Amortization (under regulatory accounting) of statutory tax rate changes | (2 | ) | (3 | ) | (1 | ) | (3 | ) | ||||||||||
Texas margin tax, net of federal tax benefit | 12 | 11 | (1 | ) | 8 | |||||||||||||
Medicare subsidy | (6 | ) | (5 | ) | (2 | ) | (5 | ) | ||||||||||
Nondeductible losses (gains) on benefit plan investments | (1 | ) | 4 | — | (2 | ) | ||||||||||||
Other, including audit settlements | 2 | 7 | 3 | 17 | ||||||||||||||
Income tax expense | $ | 173 | $ | 217 | $ | 31 | $ | 159 | ||||||||||
Effective rate | 35.1 | % | — | 32.6 | % | 37.7 | % | |||||||||||
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Deferred income taxes provided for temporary differences based on tax laws in effect at the December 31, 2009 and 2008 balance sheet dates are as follows:
| Successor | ||||||||||||||||||||
| December 31, 2009 | December 31, 2008 (a) | |||||||||||||||||||
| Total | Current | Noncurrent | Total | Current | Noncurrent | |||||||||||||||
Deferred Income Tax Assets: | ||||||||||||||||||||
Alternative minimum tax credit carryforwards | $ | 10 | $ | 10 | $ | — | $ | 54 | $ | 54 | $ | — | ||||||||
Total | 10 | 10 | — | 54 | 54 | — | ||||||||||||||
Deferred Income Tax Liabilities: | ||||||||||||||||||||
Basis difference in Oncor partnership | 1,369 | — | 1,369 | 1,333 | — | 1,333 | ||||||||||||||
Total | 1,369 | — | 1,369 | 1,333 | — | 1,333 | ||||||||||||||
Net Deferred Income Tax (Asset) Liability | $ | 1,359 | $ | (10 | ) | $ | 1,369 | $ | 1,279 | $ | (54 | ) | $ | 1,333 | ||||||
| (a) | See Note 13. |
At December 31, 2009, Oncor Holdings had $10 million of alternative minimum tax (AMT) credit carryforwards available to offset future tax sharing payments. The AMT credit carryforwards have no expiration date.
The component of deferred income tax liabilities referred to as “basis difference in Oncor partnership” arose as a result of the Oncor equity interests sale (see Note 14) at which time Oncor became a partnership for US federal income tax purposes. The amount of this basis difference at the date of the transaction represented Oncor Holdings’ interest (approximately 80%) in the net deferred tax liabilities related to Oncor’s individual operating assets and liabilities. The remaining net deferred tax liabilities associated with Oncor ($321 million at December 31, 2009) that are attributable to the noncontrolling interests have been reclassified as other noncurrent liabilities (see Note 20).
See Note 6 for discussion regarding accounting for uncertain tax positions.
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| 8. | REGULATORY ASSETS AND LIABILITIES |
Recognition of regulatory assets and liabilities and the amortization periods over which they are expected to be recovered or refunded through rate regulation reflect the decisions of the PUCT. Components of the regulatory assets and liabilities are provided in the table below. Amounts not earning a return through rate regulation are noted. On August 31, 2009, the PUCT issued a final order on Oncor’s rate review filed in June 2008. The rate review included a determination of the recoverability of regulatory assets as of December 31, 2007, including the recoverability period of those assets deemed allowable by the PUCT. The PUCT’s findings included denial of recovery of certain regulatory assets primarily related to business restructuring costs and rate case expenses, which resulted in a $25 million charge ($16 million after-tax) in the third quarter 2009 reported as write off of regulatory assets.
| Remaining Rate Recovery/Amortization Period as of December 31, 2009 | Carrying Amount | |||||||
| December 31, 2009 | December 31, 2008 | |||||||
Regulatory assets: | ||||||||
Generation-related regulatory assets securitized by transition bonds (a) | 7 years | $ | 759 | $ | 865 | |||
Employee retirement costs | 5 years | 80 | — | |||||
Employee retirement costs to be reviewed (b)(c) | To be determined | 41 | 100 | |||||
Employee retirement liability (a)(c)(d) | To be determined | 768 | 559 | |||||
Self-insurance reserve (primarily storm recovery costs) — net | 7 years | 137 | — | |||||
Self-insurance reserve to be reviewed (b)(c) | To be determined | 106 | 214 | |||||
Nuclear decommissioning cost under-recovery (a)(c)(e) | Not applicable | 85 | 127 | |||||
Securities reacquisition costs (pre-industry restructure) | 8 years | 62 | 68 | |||||
Securities reacquisition costs (post-industry restructure) | Terms of related debt | 27 | 29 | |||||
Recoverable amounts for/in lieu of deferred income taxes — net | Life of related asset or liability | 68 | 77 | |||||
Rate case expenses (f) | Largely 3 years | 9 | 10 | |||||
Rate case expenses to be reviewed (b)(c) | To be determined | 1 | — | |||||
Advanced meter customer education costs | 10 years | 4 | 2 | |||||
Deferred conventional meter depreciation | 10 years | 14 | — | |||||
Energy efficiency performance bonus | 1 year | 9 | — | |||||
Business restructuring costs (g) | Not applicable | — | 20 | |||||
Total regulatory assets | 2,170 | 2,071 | ||||||
Regulatory liabilities: | ||||||||
Committed spending for demand-side management initiatives (a) | 3 years | 78 | 96 | |||||
Deferred advanced metering system revenues | 10 years | 57 | — | |||||
Investment tax credit and protected excess deferred taxes | Various | 44 | 49 | |||||
Over-collection of securitization (transition) bond revenues (a) | 7 years | 27 | 28 | |||||
Other regulatory liabilities (a) | Various | 5 | 6 | |||||
Total regulatory liabilities | 211 | 179 | ||||||
Net regulatory asset | $ | 1,959 | $ | 1,892 | ||||
| (a) | Not earning a return in the regulatory rate-setting process. |
| (b) | Costs incurred since the period covered under the last rate review. |
| (c) | Recovery is specifically authorized by statute, subject to reasonableness review by the PUCT. |
| (d) | Represents unfunded liabilities recorded in accordance with pension and OPEB accounting standards. |
| (e) | Offset by an intercompany payable to TCEH. See Note 19. |
| (f) | Rate case expenses totaling $4 million were disallowed by the PUCT and written off in the third quarter of 2009. |
| (g) | All previously recorded business restructuring costs were disallowed by the PUCT and written off in the third quarter of 2009. |
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In September 2008, the PUCT approved a settlement for Oncor to recover its estimated future investment for advanced metering deployment. Oncor began billing the advanced metering surcharge in the January 2009 billing month cycle. The surcharge is expected to total $1.023 billion over the 11-year recovery period and includes a cost recovery factor of $2.19 per month per residential retail customer and $2.39 to $5.15 per month for non-residential retail customers. Oncor Holdings accounts for the difference between the surcharge billings for advanced metering facilities and the allowed revenues under the surcharge provisions, which are based on expenditures and an allowed return, as a regulatory asset or liability. Such differences arise principally as a result of timing of expenditures. As indicated in the table above, the regulatory liability at December 31, 2009 totaled $57 million.
See Note 2 for a discussion of effects of purchase accounting on the carrying value of generation-related regulatory assets, Note 4 for discussion of effects on regulatory assets and liabilities of the stipulation approved by the PUCT and Note 19 for additional information regarding nuclear decommissioning cost recovery.
| 9. | TRADE ACCOUNTS RECEIVABLE AND SALE OF RECEIVABLES PROGRAM |
Trade Accounts Receivable
| December 31, 2009 | December 31, 2008 | |||||||
Gross trade accounts receivable | $ | 395 | $ | 359 | ||||
Trade accounts receivable from TCEH | (150 | ) | (135 | ) | ||||
Allowance for uncollectible accounts | (2 | ) | (7 | ) | ||||
Trade accounts receivable from nonaffiliates — net | $ | 243 | $ | 217 | ||||
Gross trade accounts receivable at December 31, 2009 and 2008 included unbilled revenues of $141 million and $140 million, respectively.
In April 2009, the PUCT finalized a new rule relating to the Certification of Retail Electric Providers. Under the new rule, write-offs of uncollectible amounts owed by REPs are deferred as a regulatory asset. Accordingly, Oncor Holdings recognized a $3 million one-time reversal of bad debt expense in 2009 representing bad debt reserves previously recognized for nonaffiliated REP accounts receivable. Due to the commitments made to the PUCT in connection with the Merger, Oncor may not recover bad debt expense, or certain other costs and expenses, from rate payers in the event of a default or bankruptcy by an affiliate REP.
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Sale of Receivables
Prior to the Merger, Oncor participated in an accounts receivable securitization program established by EFH Corp. for certain of its subsidiaries, the activity under which was accounted for as a sale of accounts receivable in accordance with transfers and servicing accounting standards. Under the program, Oncor sold trade accounts receivable to TXU Receivables Company, a consolidated wholly-owned bankruptcy-remote direct subsidiary of EFH Corp., which sold undivided interests in those purchased accounts receivable for cash to special purpose entities established by financial institutions (the funding entities). In connection with the Merger, the accounts receivable securitization program was amended. Concurrently, the financial institutions required that Oncor repurchase all of the receivables it had previously sold to TXU Receivables Company, which totaled $254 million. Oncor funded such repurchases through borrowings under its credit facility of $113 million, and the related subordinated note receivable from TXU Receivables Company in the amount of $141 million was canceled. Oncor is no longer a participant in the accounts receivable securitization program.
Under the program, new trade receivables generated by Oncor were continuously purchased by TXU Receivables Company with the proceeds from collections of receivables previously purchased. Changes in the amount of funding under the program, through changes in the amount of undivided interests sold by TXU Receivables Company, reflected seasonal variations in the level of accounts receivable, changes in collection trends as well as other factors such as changes in delivery fees and volumes. TXU Receivables Company issued subordinated notes payable to Oncor for the difference between the face amount of the uncollected accounts receivable purchased, less a discount, and cash paid to Oncor that was funded by the sale of the undivided interests.
The discount from face amount on the purchase of receivables principally funded program fees paid by TXU Receivables Company to the funding entities. The discount also funded a servicing fee paid by TXU Receivables Company to EFH Corporate Services Company, a direct subsidiary of EFH Corp., but the amounts were immaterial. The program fees, referred to as losses on sale of the receivables under transfers and servicing accounting standards, consisted primarily of interest costs on the underlying financing and totaled $6 million and averaged 6.4% (on an annualized basis) as a percentage of the average funding under the program for the Predecessor period from January 1, 2007 through October 10, 2007. These fees represented essentially all of the net incremental costs of the program to Oncor and were reported in operation and maintenance expenses.
Funding under the program decreased $86 million to zero in 2007 with Oncor’s exit from the program. Funding increases or decreases under the program were reflected as operating cash flow activity in the statement of cash flows. The carrying amount of the retained interests in the accounts receivable balance approximated fair value due to the short-term nature of the collection period.
Activities of TXU Receivables Company related to Oncor in 2007 were as follows:
| Successor (a) | Predecessor | ||||||||
| Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | ||||||||
Cash collections on accounts receivable | $ | — | $ | 1,082 | |||||
Face amount of new receivables purchased | — | (1,156 | ) | ||||||
Discount from face amount of purchased receivables | — | 5 | |||||||
Program fees paid to funding entities | — | (6 | ) | ||||||
Increase in subordinated notes payable | — | 48 | |||||||
Repurchase of receivables previously sold | 113 | — | |||||||
Operating cash flows used by (provided to) Oncor under the program | $ | 113 | $ | (27 | ) | ||||
| (a) | Represents final activities related to Oncor’s exit from the sale of receivables program. |
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| 10. | BORROWINGS UNDER CREDIT FACILITIES |
At December 31, 2009, Oncor had a $2.0 billion secured revolving credit facility, expiring October 10, 2013, to be used for its working capital and general corporate purposes, including issuances of commercial paper and letters of credit. Oncor may request increases in the commitments under the facility in any amount up to $500 million, subject to the satisfaction of certain conditions. Amounts borrowed under the facility, once repaid, can be borrowed again by Oncor from time to time. Borrowings are classified as short-term on the balance sheet. In May 2008, Oncor secured this credit facility with a first priority lien on certain of its transmission and distribution assets. Oncor also secured all of its existing long-term debt securities (excluding the transition bonds) with the same lien in accordance with the terms of those securities. The lien contains customary provisions allowing Oncor to use the assets in its business, as well as to replace and/or release collateral as long as the market value of the aggregate collateral is at least 115% of the aggregate secured debt. The lien may be terminated at Oncor’s option upon the termination of Oncor’s current credit facility.
At December 31, 2009, Oncor had outstanding borrowings under the credit facility totaling $616 million with an interest rate of 0.58% at the end of the period. At December 31, 2008, Oncor had outstanding borrowings under the credit facility totaling $337 million with an interest rate of 1.98% at the end of the period. Availability under the credit facility as of December 31, 2009 was $1.262 billion. This availability excludes $122 million of commitments from a subsidiary of Lehman Brothers Holding Inc. (such subsidiary, Lehman) that has filed for bankruptcy under Chapter 11 of the US Bankruptcy Code. Availability under the credit facility as of December 31, 2008 was $1.508 billion, which excluded $155 million of commitments from Lehman.
Under the terms of Oncor’s revolving credit facility, the commitments of the lenders to make loans to Oncor are several and not joint. Accordingly, if any lender fails to make loans to Oncor, Oncor’s available liquidity could be reduced by an amount up to the aggregate amount of such lender’s commitments under the facility.
Borrowings under this credit facility bear interest at per annum rates equal to, at Oncor’s option, (i) adjusted LIBOR plus a spread of 0.275% to 0.800% (depending on the ratings assigned to Oncor’s senior secured debt) or (ii) a base rate (the higher of (1) the prime rate of JPMorgan Chase Bank, N.A. and (2) the federal funds effective rate plus 0.50%). Under option (i) and based on Oncor’s ratings as of December 31, 2009, its LIBOR-based borrowings, which apply to all outstanding borrowings at December 31, 2009, bear interest at LIBOR plus 0.350%.
A facility fee is payable at a rate per annum equal to 0.100% to 0.200% (depending on the rating assigned to Oncor’s senior secured debt) of the commitments under the facility. Based on Oncor’s ratings as of December 31, 2009, its facility fee is 0.125%. A utilization fee is payable on the average daily amount of borrowings in excess of 50% of the commitments under the facility at a rate per annum equal to 0.125% per annum.
The credit facility contains customary covenants for facilities of this type, restricting, subject to certain exceptions, Oncor and its subsidiary from, among other things:
| • | incurring additional liens; |
| • | entering into mergers and consolidations; |
| • | selling certain assets, and |
| • | making acquisitions and investments in subsidiaries. |
In addition, the credit facility requires that Oncor maintain a consolidated senior debt-to-capitalization ratio of no greater than 0.65 to 1.00 and observe certain customary reporting requirements and other affirmative covenants.
The credit facility contains certain customary events of default for facilities of this type, the occurrence of which would allow the lenders to accelerate all outstanding loans and terminate their commitments under the facility.
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| 11. | LONG-TERM DEBT |
At December 31, 2009 and 2008, long-term debt consisted of the following:
| December 31, 2009 | December 31, 2008 | |||||||
Oncor (a): | ||||||||
6.375% Fixed Senior Notes due May 1, 2012 | $ | 700 | $ | 700 | ||||
5.950% Fixed Senior Notes due September 1, 2013 | 650 | 650 | ||||||
6.375% Fixed Senior Notes due January 15, 2015 | 500 | 500 | ||||||
6.800% Fixed Senior Notes due September 1, 2018 | 550 | 550 | ||||||
7.000% Fixed Debentures due September 1, 2022 | 800 | 800 | ||||||
7.000% Fixed Senior Notes due May 1, 2032 | 500 | 500 | ||||||
7.250% Fixed Senior Notes due January 15, 2033 | 350 | 350 | ||||||
7.500% Fixed Senior Notes due September 1, 2038 | 300 | 300 | ||||||
Unamortized discount | (15 | ) | (16 | ) | ||||
Total Oncor | 4,335 | 4,334 | ||||||
Oncor Electric Delivery Transition Bond Company LLC (b): | ||||||||
4.030% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2010 | 13 | 54 | ||||||
4.950% Fixed Series 2003 Bonds due in semiannual installments through February 15, 2013 | 130 | 130 | ||||||
5.420% Fixed Series 2003 Bonds due in semiannual installments through August 15, 2015 | 145 | 145 | ||||||
3.520% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2009 | — | 39 | ||||||
4.810% Fixed Series 2004 Bonds due in semiannual installments through November 15, 2012 | 197 | 221 | ||||||
5.290% Fixed Series 2004 Bonds due in semiannual installments through May 15, 2016 | 290 | 290 | ||||||
Total Oncor Electric Delivery Transition Bond Company LLC | 775 | 879 | ||||||
Unamortized fair value discount related to transition bonds (c) | (6 | ) | (9 | ) | ||||
Total consolidated (d) | 5,104 | 5,204 | ||||||
Less amount due currently | (108 | ) | (103 | ) | ||||
Total long-term debt | $ | 4,996 | $ | 5,101 | ||||
| (a) | Secured with first priority lien as discussed in Note 10. |
| (b) | The transition bonds are nonrecourse to Oncor and were issued to securitize a regulatory asset. |
| (c) | The transition bonds, which secured regulatory assets not earning a return, were fair valued as of October 10, 2007 as a result of purchase accounting. |
| (d) | According to its organizational documents, Oncor Holdings is prohibited from directly incurring indebtedness for borrowed money. |
Debt Repayments in 2009
Repayments of long-term debt in 2009 totaled $104 million and represent transition bond principal payments at scheduled maturity dates.
Debt-Related Activity in 2008
In September 2008, Oncor issued and sold senior secured notes with an aggregate principal amount of $1.5 billion consisting of $650 million aggregate principal amount of 5.95% senior secured notes maturing in September 2013, $550 million aggregate principal amount of 6.80% senior secured notes maturing in September 2018 and $300 million aggregate principal amount of 7.50% senior secured notes maturing in September 2038. Oncor used the net proceeds of approximately $1.487 billion from the sale of the notes to repay most of its borrowings under its credit facility as well as for general corporate purposes. The notes are secured by the first priority lien described in Note 10. The notes are secured equally and ratably with all of Oncor’s other secured indebtedness. If the lien is terminated, the notes will cease to be secured obligations of Oncor and will become senior unsecured general obligations of Oncor.
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Interest on these notes is payable in cash semiannually in arrears on March 1 and September 1 of each year. Oncor may redeem the notes, in whole or in part, at any time, at a price equal to 100% of their principal amount, plus accrued and unpaid interest and a “make-whole” premium. The notes also contain customary events of default, including failure to pay principal or interest on the notes when due.
Repayments of long-term debt in 2008 totaled $99 million and represent transition bond principal payments at scheduled maturity dates.
Interest Rate Hedges
In September 2008, Oncor entered into interest rate swap transactions hedging the variability of treasury bond rates used to determine the interest rates on an anticipated issuance of an aggregate of $1.0 billion of senior secured notes maturing from 2013 to 2018. The hedges were terminated the same day, and $2 million in after-tax losses were recorded as other comprehensive income. After-tax net losses of less than one million will be reclassified into net income during the next twelve months as the related hedged transactions affect net income.
Maturities
Long-term debt and transition bonds maturities are as follows:
Year | ||||
2010 | $ | 108 | ||
2011 | 113 | |||
2012 | 819 | |||
2013 | 775 | |||
2014 | 131 | |||
Thereafter | 3,179 | |||
Unamortized fair value discount | (6 | ) | ||
Unamortized discount | (15 | ) | ||
Total | $ | 5,104 | ||
Fair Value of Long-Term Debt
The estimated fair value of long-term debt (including current maturities) totaled $5.644 billion and $4.990 billion at December 31, 2009 and 2008, respectively, and the carrying amount totaled $5.104 billion and $5.204 billion, respectively. The fair value is estimated at the lesser of either the call price or the market value as determined by quoted market prices.
| 12. | COMMITMENTS AND CONTINGENCIES |
Leases
At December 31, 2009, future minimum lease payments under operating leases (with initial or remaining noncancelable lease terms in excess of one year) were as follows:
Year | |||
2010 | $ | 12 | |
2011 | 12 | ||
2012 | 10 | ||
2013 | 4 | ||
2014 | 4 | ||
Thereafter | 7 | ||
Total future minimum lease payments | $ | 49 | |
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Rent charged to operation and maintenance expense totaled $11 million and $10 million for the years ended December 31, 2009 and 2008, respectively, $3 million for the period October 11, 2007 through December 31, 2007 and $7 million for the Predecessor period January 1, 2007 through October 10, 2007.
Capital Expenditures
Oncor and Texas Holdings agreed to the terms of a stipulation with major interested parties to resolve all outstanding issues in the PUCT review related to the Merger. As one of the provisions of this stipulation, Oncor committed to minimum capital spending of $3.6 billion over the five-year period ending December 31, 2012, subject to certain defined conditions. See Note 4.
Efficiency Spending
Oncor is required to annually invest in programs designed to improve customer electricity demand efficiencies to satisfy its ongoing regulatory requirements. The 2010 requirement is $44 million. Oncor also committed to invest $100 million in these programs in excess of regulatory requirements over the five years ending in 2012. See Note 4.
Guarantees
Oncor has entered into contracts that contain guarantees to unaffiliated parties that could require performance or payment under certain conditions.
Oncor is the lessee under various operating leases that obligate it to guarantee the residual values of the leased assets. At December 31, 2009, both the aggregate maximum amount of residual values guaranteed and the estimated residual recoveries totaled approximately $6 million. These leased assets consist primarily of vehicles used in distribution activities. The average life of the residual value guarantees under the lease portfolio is approximately two years.
Legal Proceedings
Oncor Holdings is involved in various legal and administrative proceedings in the normal course of business the ultimate resolution of which, in the opinion of management, should not have a material effect upon its financial position, results of operations or cash flows.
Labor Contracts
Certain Oncor employees are represented by a labor union and covered by a collective bargaining agreement that will expire in October 2010. In June 2009, a group of approximately 50 employees voted to decertify the labor union as their representative. In December 2009, a group of approximately 350 employees elected to be represented by a labor union. The negotiation of a new labor agreement and the representation of this group of additional employees is not expected to have a material effect on Oncor Holdings’ financial position, results of operations or cash flows.
Environmental Contingencies
Oncor must comply with environmental laws and regulations applicable to the handling and disposal of hazardous waste. Oncor is in compliance with all current laws and regulations; however, the impact, if any, of changes to existing regulations or the implementation of new regulations is not determinable. The costs to comply with environmental regulations can be significantly affected by the following external events or conditions:
| • | changes to existing state or federal regulation by governmental authorities having jurisdiction over control of toxic substances and hazardous and solid wastes, and other environmental matters, and |
| • | the identification of additional sites requiring clean-up or the filing of other complaints in which Oncor Holdings may be asserted to be a potential responsible party. |
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| 13. | MEMBERSHIP INTERESTS |
Successor
Cash Distributions— On February 11, 2010, the board of directors declared a cash distribution of between $34 million and $41 million to be paid to Intermediate Holding on February 19, 2010.
During 2009, Oncor Holdings’ board of directors declared, and Oncor Holdings paid, the following cash distributions to Intermediate Holding:
Declaration Date | Payment Date | Amount Paid | |||
November 12, 2009 | November 13, 2009 | $ | 99 | ||
August 18, 2009 | August 19, 2009 | $ | 59 | ||
May 19, 2009 | May 20, 2009 | $ | 40 | ||
February 18, 2009 | March 3, 2009 | $ | 18 | ||
During 2008, Oncor Holdings’ board of directors declared, and Oncor Holdings paid, the following cash distributions to Intermediate Holding:
Declaration Date | Payment Date | Amount Paid | |||
November 13, 2008 | November 14, 2008 | $ | 117 | ||
August 20, 2008 | August 21, 2008 | $ | 78 | ||
May 14, 2008 | May 15, 2008 | $ | 78 | ||
February 20, 2008 | March 31, 2008 | $ | 57 | ||
The net proceeds of $1.253 billion from Oncor’s sale of equity interests in November 2008 were distributed to Intermediate Holding and ultimately to EFH Corp.
While there are no direct restrictions on Oncor Holdings’ ability to distribute its net income that are currently material, substantially all of Oncor Holdings’ net income is derived from Oncor. The boards of directors of each of Oncor and Oncor Holdings, which are composed of a majority of independent directors, can withhold distributions to the extent the boards determine that it is necessary to retain such amounts to meet expected future requirements of Oncor and/or Oncor Holdings. For the period beginning October 11, 2007 and ending December 31, 2012, distributions paid by Oncor (other than distributions of the proceeds of any issuance of limited liability company units) are limited by the Limited Liability Company Agreement to an amount not to exceed Oncor’s net cumulative income determined in accordance with GAAP, as adjusted by applicable orders of the PUCT. Such adjustments include deducting the $72 million ($46 million after tax) one-time refund to customers in September 2008 and deducting funds spent as part of the $100 million commitment for additional demand-side management or other energy efficiency initiatives (see Note 4) of which $22 million ($14 million after tax) has been spent through December 31, 2009, neither of which impacted net income due to purchase accounting, and removing the effect of the $860 million goodwill impairment charge from fourth quarter 2008 net income available for distribution. The goodwill impairment charge and refund are described in Notes 3 and 4, respectively. Distributions are further limited by Oncor’s required regulatory capital structure, as determined by the PUCT, to be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. For 2009, $35 million of net income was restricted from being used to make distributions on membership interests. The net proceeds of $1.253 billion received from the 2008 sale of equity interests to Texas Transmission and certain members of Oncor’s management and board of directors were excluded from these distribution limitations.
Effect of Sale of Noncontrolling Interests — The total amount of proceeds from the sale of noncontrolling interests in Oncor discussed in Note 14 was less than the carrying value of the interests sold by $265 million, which reflects the fact that Oncor’s carrying value after purchase accounting is based on the Merger value, while the noncontrolling interests sale value did not include a control premium. The difference was accounted for as a reduction of membership interests.
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During the preparation of Oncor Holdings’ December 31, 2009 financial statements, Oncor Holdings determined that deferred income taxes related to its interest in Oncor should have been recorded upon the sale of noncontrolling interests in November 2008. Accordingly, the December 31, 2008 balance of noncurrent accumulated deferred income tax liabilities has been increased by $141 million (from the $1.192 billion previously reported) and total membership interests at that date has been decreased by the same amount (from the $6.801 billion previously reported). The recognition of the deferred tax liability is the result of applying rules for income tax accounting related to outside basis differences. This error did not affect net income or cash flows previously reported.
Equity Contributions— As a result of the Merger, all outstanding unvested stock-based incentive compensation awards previously granted by EFH Corp. to Oncor employees vested and such employees became entitled to receive the $69.25 per share Merger consideration. The settlement of these awards totaled $24 million and was accounted for as an equity contribution from EFH Corp., as was the settlement of $4 million of cash incentive compensation awards. See Note 18 for further discussion of stock-based compensation, including a SARs Plan implemented in November 2008.
In connection with the Merger, Texas Holdings paid a $12 million fee related to Oncor’s $2 billion revolving credit facility. Such payment was accounted for as an investment by Texas Holdings.
In March 2008, Oncor Holdings distributed its investment in an entity with telecommunications-related activities that are not part of Oncor’s current operations totaling $24 million to Intermediate Holding.
Predecessor
No shares of Oncor’s common stock were held by or for its own account, nor were any shares of such capital stock reserved for its officers and employees or for options, warrants, conversions and other rights in connection therewith.
Under accounting standards for share-based payments, expense related to EFH Corp.’s stock-based incentive compensation awards granted to Oncor’s employees was accounted for as a noncash capital contribution from EFH Corp. Accordingly, Oncor recorded a credit to its common stock account of $3 million in the period January 1, 2007 through October 10, 2007.
Oncor recorded a credit to common stock of $15 million in the period January 1, 2007 through October 10, 2007 arising from the excess tax benefit generated by the distribution date value of the stock-based incentive awards exceeding the reported compensation expense. The $15 million credit (benefit) in 2007 was realized in the Successor period in conjunction with a tax payment to EFH Corp.
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| 14. | NONCONTROLLING INTERESTS |
In November 2008, equity interests in Oncor were sold to Texas Transmission for $1.254 billion in cash. Equity interests were also indirectly sold to certain members of Oncor’s board of directors and its management team. Accordingly, after giving effect to all equity issuances, as of December 31, 2009, Oncor’s ownership was as follows: 80.03% held by Oncor Holdings, 0.22% held indirectly by Oncor’s management and board of directors and 19.75% held by Texas Transmission.
The proceeds (net of closing costs) of $1.253 billion received by Oncor from Texas Transmission and the members of Oncor management upon completion of these transactions were distributed to Oncor Holdings who distributed the proceeds to Intermediate Holding and ultimately to EFH Corp.
See Note 13 for discussion of amounts recorded as a reduction of membership interests as a result of the sale of Oncor interests.
The noncontrolling interests balance reported in the December 31, 2009 and 2008 consolidated balance sheets was $1.363 million and 1.355 billion, respectively. The noncontrolling interests balance reported in the December 31, 2009 consolidated balance sheet represented the proportional share of Oncor’s net assets at the date of the transaction less $96 million representing the noncontrolling interests’ share of Oncor’s net losses for the periods subsequent to the transaction (including the goodwill impairment charge), net of $58 million in cash distributions.
| 15. | INVESTMENTS |
The investments balance consists of the following:
| December 31, 2009 | December 31, 2008 | |||||
Assets related to employee benefit plans, including employee savings programs, net of distributions | $ | 67 | $ | 65 | ||
Investment in unconsolidated affiliates | 3 | 5 | ||||
Land | 2 | 2 | ||||
Total investments | $ | 72 | $ | 72 | ||
Assets Related to Employee Benefit Plans
The majority of these assets represent cash surrender values of life insurance policies that are purchased to fund liabilities under deferred compensation plans. As of December 31, 2009, Oncor pays the premiums and is the beneficiary of these life insurance policies. EFH Corp. was the previous beneficiary. As of December 31, 2009 and 2008, the face amount of these policies totaled $138 million and $151 million, and the net cash surrender values totaled $52 million and $53 million, respectively. Changes in cash surrender value are netted against premiums paid. Other investment assets held to satisfy deferred compensation liabilities are recorded at market value.
Restricted Cash
| At December 31, 2009 | At December 31, 2008 | |||||||||||
| Current Assets | Noncurrent Assets | Current Assets | Noncurrent Assets | |||||||||
Customer collections related to securitization (transition) bonds used only to service debt and pay expenses | $ | 47 | $ | — | $ | 51 | $ | — | ||||
Reserve for fees associated with transition bonds | — | 10 | — | 10 | ||||||||
Reserve for shortfalls of transition bond charges | — | 4 | — | 6 | ||||||||
Total restricted cash | $ | 47 | $ | 14 | $ | 51 | $ | 16 | ||||
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| 16. | TERMINATION OF OUTSOURCING ARRANGEMENTS |
In connection with the closing of the Merger, EFH Corp., Oncor and TCEH commenced a review, under the change of control provision, of certain outsourcing arrangements with Capgemini, Capgemini America, Inc. and Capgemini North America, Inc. (collectively, CgE). In 2008, Oncor executed a Separation Agreement with CgE. Simultaneous with the execution of that Separation Agreement, EFH Corp. and TCEH entered into a substantially similar Separation Agreement with CgE. The Separation Agreements principally provide for (i) notice of termination of each of the Master Framework Agreements, dated as of May 17, 2004, each as amended, between Capgemini and each of Oncor and TCEH and the related service agreements under each of the Master Framework Agreements and (ii) termination of the joint venture arrangements between EFH Corp. (and its applicable subsidiaries) and CgE. Under the Master Framework Agreements and related services agreements, Capgemini provided to Oncor and EFH Corp. and its other subsidiaries outsourced support services, including information technology, customer care and billing, human resources, procurement and certain finance and accounting activities.
As a result, during the fourth quarter of 2008:
| • | EFH Corp. received approximately $70 million in cash in exchange for the termination of a purchase option agreement pursuant to which subsidiaries of EFH Corp. had the right to “put” to Capgemini (and Capgemini had the right to “call” from a subsidiary of EFH Corp.) EFH Corp.’s 2.9% limited partnership interest in Capgemini and licensed assets, principally software, upon the expiration of the Master Framework Agreements in 2014 or, in some circumstances, earlier. Oncor received $20 million of such proceeds, reflecting its share of the put option value. |
| • | The parties entered into a mutual release of all claims under the Master Framework Agreement and related services agreements, subject to certain defined exceptions, and Oncor received $4 million in cash in settlement of such claims. |
The carrying value of Oncor’s share of the put option value was $48 million prior to the application of purchase accounting (recorded as a noncurrent asset). The effects of the termination of the outsourcing arrangements, including an accrued liability of $16 million for incremental costs to exit and transition the services, were included in the final purchase price allocation. See Note 2 for additional disclosure, including a reversal to income of a portion of the liability recorded in purchase accounting.
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| 17. | PENSION AND OTHER POSTRETIREMENT EMPLOYEE BENEFITS (OPEB) PLANS |
Pension Plan
Oncor is a participating employer in the EFH Retirement Plan (Retirement Plan), a defined benefit pension plan sponsored by EFH Corp. The Retirement Plan is a qualified pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and is subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (ERISA). All benefits are funded by the participating employers. The Retirement Plan provides benefits to participants under one of two formulas: (i) a Cash Balance Formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits or (ii) a Traditional Retirement Plan Formula based on years of service and the average earnings of the three years of highest earnings. The interest component of the Cash Balance Formula is variable and is determined using the yield on 30-year Treasury bonds. Under the Cash Balance Formula, future increases in earnings will not apply to prior service costs.
All eligible employees hired after January 1, 2001 participate under the Cash Balance Formula. Certain employees who, prior to January 1, 2002, participated under the Traditional Retirement Plan Formula, continue their participation under that formula. It is EFH Corp.’s policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations.
Oncor also participated in an EFH Corp. supplemental retirement plan for certain employees, whose retirement benefits cannot be fully earned under the qualified Retirement Plan, the information for which is included below. Oncor ceased participation in the EFH Corp. plan and implemented its own supplemental retirement plan effective January 1, 2010.
OPEB Plan
Oncor participates with EFH Corp. and certain other affiliated subsidiaries of EFH Corp. to offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree’s age and years of service.
Pension and OPEB Costs Recognized as Expense
The following details net pension and OPEB costs recognized as expense:
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Pension costs | $ | 35 | $ | 15 | $ | 3 | $ | 21 | ||||||||||
OPEB costs | 55 | 44 | 9 | 50 | ||||||||||||||
Total benefit costs | 90 | 59 | 12 | 71 | ||||||||||||||
Less amounts deferred principally as a regulatory asset or property | (66 | ) | (42 | ) | (8 | ) | (43 | ) | ||||||||||
Net amounts recognized as expense | $ | 24 | $ | 17 | $ | 4 | $ | 28 | ||||||||||
Consistent with accounting standards related to employers’ accounting for pensions, EFH Corp. uses the calculated value method to determine the market-related value of the assets held in its trust. EFH Corp. includes the realized and unrealized gains or losses in the market-related value of assets over a rolling four-year period. Each year, 25% of such gains and losses for the current year and for each of the preceding three years is included in the market-related value. Each year, the market-related value of assets is increased for contributions to the plan and investment income and is decreased for benefit payments and expenses for that year.
The pension and OPEB amounts provided represent allocations to Oncor of amounts related to EFH Corp.’s plans.
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Regulatory Recovery of Pension and OPEB Costs
PURA provides for the recovery by Oncor of pension and OPEB costs for all applicable former employees of the regulated predecessor integrated electric utility, which in addition to Oncor’s active and retired employees consists largely of active and retired personnel engaged in TCEH’s activities, related to service of those additional personnel prior to the deregulation and disaggregation of EFH Corp.’s businesses effective January 1, 2002. Accordingly, Oncor and TCEH entered into an agreement whereby Oncor assumed responsibility for applicable pension and OPEB costs related to those personnel.
Oncor is authorized to establish a regulatory asset or liability for the difference between the amounts of pension and OPEB costs approved in current billing rates and the actual amounts that would otherwise have been recorded as charges or credits to earnings. Amounts deferred are ultimately subject to regulatory approval. As of December 31, 2009, Oncor had recorded regulatory assets totaling $889 million related to pension and OPEB costs, including amounts related to deferred expenses as well as amounts related to unfunded liabilities that otherwise would be recorded as other comprehensive income.
Assumed Discount Rate
The discount rates reflected in net pension and OPEB costs are 6.90% (6.85% for OPEB) and 6.55% for the years ended December 31, 2009 and 2008, respectively, 6.45% for the period October 11, 2007 through December 31, 2007 and 5.90% for the period January 1, 2007 through October 10, 2007. The expected rate of return on plan assets reflected in the 2009 cost amounts is 8.25% for the pension plan and 7.64% for OPEBs.
Pension and OPEB Plan Cash Contributions
Contributions to the benefit plans were as follows:
| December 31, | |||||||||
| 2009 | 2008 | 2007 | |||||||
Pension plan contributions | $ | 66 | $ | 46 | $ | 3 | |||
OPEB plan contributions | 18 | 31 | 33 | ||||||
Total contributions | $ | 84 | $ | 77 | $ | 36 | |||
Estimated funding in 2010 of the pension and OPEB plans is $43 million and $18 million, respectively.
Thrift Plan
Employees of Oncor may participate in a qualified savings plan, the EFH Corp. Thrift Plan (Thrift Plan). This plan is a participant-directed defined contribution plan intended to qualify under Section 401(a) of the Code, and is subject to the provisions of ERISA. Under the terms of the Thrift Plan, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax applicable payroll deductions, the lesser of 75% of their regular salary or wages or the maximum amount permitted under law. Employees who earn more than such threshold may contribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% of the first 6% of employee contributions for employees who are covered under the Cash Balance Formula of the Retirement Plan, and 75% of the first 6% of employee contributions for employees who are covered under the Traditional Retirement Plan Formula of the Retirement Plan. Effective January 1, 2006 through October 10, 2007, employees could reallocate or transfer all or part of their accumulated or future employer matching contributions to any of the plan’s other investment options. As of October 10, 2007, employer matching contributions are made in cash and may be allocated by participants to any of the plan’s investment options. Oncor’s contributions to the Thrift Plan totaled $11 million, $9 million, $2 million and $13 million in the years ended December 31, 2009 and 2008, the period October 11, 2007 through December 31, 2007 and the period January 1, 2007 through October 10, 2007, respectively.
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| 18. | STOCK-BASED COMPENSATION |
Successor
In 2008, Oncor established the Oncor Electric Delivery Company LLC Stock Appreciation Rights Plan (the SARs Plan) under which certain employees of Oncor may be granted stock appreciation rights (SARs) payable in cash, or in some circumstances, Oncor units. Two types of SARs may be granted under the SARs Plan. Time-based SARs (Time SARs) vest solely based upon continued employment ratably on an annual basis on each of the first five anniversaries of the grant date. Performance-based SARs (Performance SARs) vest based upon both continued employment and the achievement of a predetermined level of Oncor EBITDA over time, generally ratably over five years based upon annual Oncor EBITDA levels, with provisions for vesting if the annual levels are not achieved but cumulative two- or three-year total Oncor EBITDA levels are achieved. Time and Performance SARs may also vest in part or in full upon the occurrence of certain specified liquidity events and are exercisable only upon the occurrence of certain specified liquidity events. Since the exercisability of the Time and Performance SARs is conditioned upon the occurrence of a liquidity event, compensation expense will not be recorded until it is probable that a liquidity event will occur. Generally, awards under the SARs Plan terminate on the tenth anniversary of the grant, unless the participant’s employment is terminated earlier under certain circumstances.
In February 2009, Oncor also established the Oncor Electric Delivery Company LLC Director Stock Appreciation Rights Plan (the Director SARs Plan) under which certain non-employee members of Oncor’s board of directors and other persons having a relationship with Oncor may be granted SARs payable in cash, or in some circumstances, Oncor units. SARs granted under the Director SARs Plan vest in eight equal quarterly installments over a two-year period and are exercisable only upon the occurrence of certain specified liquidity events. Since the exercisability of these SARs is conditioned upon the occurrence of a liquidity event, expense will not be recorded until it is probable a liquidity event will occur.
SARs under the SARs Plan and the Director SARs Plan are generally payable in cash based on the fair market value of the SAR on the date of exercise. No SARs were granted under the SARs Plan during the year ended December 31, 2009. Oncor granted 6.9 million Time SARs under the SARs Plan during the year ended December 31, 2008, and Time SARS vested at December 31, 2009 totaled 2.8 million. Oncor granted 6.9 million Performance SARs under the SARs Plan during the year ended December 31, 2008, and Performance SARs vested at December 31, 2009 totaled 1.4 million. Oncor granted 55 thousand SARs under the Director SARs Plan during the year ended December 31, 2009, and SARs vested under the Director SARs Plan at December 31, 2009 totaled 27.5 thousand. There were no SARs under either plan eligible for exercise at December 31, 2009.
Predecessor
Prior to the Merger, Oncor bore the costs of the EFH Corp. shareholder-approved long-term incentive plans for applicable management personnel engaged in Oncor’s business activities. EFH Corp. provided discretionary awards of performance units to qualified management employees that were payable in its common stock. The awards generally vested over a three-year period, and the number of shares ultimately earned was based on the performance of EFH Corp.’s stock over the vesting period as compared to peer companies and established thresholds. EFH Corp. established restrictions that limited certain employees’ opportunities to liquidate vested awards.
EFH Corp. determined the fair value of its stock-based compensation awards utilizing a valuation model that took into account three principal factors: expected volatility of the stock price of EFH Corp. and peer group companies, dividend rate of EFH Corp. and peer group companies and the restrictions limiting liquidation of vested stock awards. Based on the fair values determined under this model, Oncor’s reported expense related to the awards totaled $3 million ($2 million after-tax) for the period January 1, 2007 through October 10, 2007. There were no awards granted in 2007.
With respect to awards to Oncor’s employees, the fair value of awards that vested in the period January 1, 2007 through October 10, 2007 totaled $84 million based on the vesting date share prices.
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| 19. | RELATED-PARTY TRANSACTIONS |
The following represent significant related-party transactions of Oncor Holdings:
| • | Oncor records revenue from TCEH, principally for electricity delivery fees, which totaled $1.0 billion for each of the years ended December 31, 2009 and 2008, $209 million for the period October 11, 2007 through December 31, 2007 and $823 million for the period January 1, 2007 through October 10, 2007. |
| • | Oncor records interest income from TCEH with respect to Oncor’s generation-related regulatory assets, which have been securitized through the issuance of transition bonds by Oncor’s bankruptcy-remote financing subsidiary. The interest income serves to offset Oncor’s interest expense on the transition bonds. This interest income totaled $42 million and $46 million for the years ended December 31, 2009 and 2008, respectively, $11 million for the period October 11, 2007 through December 31, 2007 and $38 million for the period January 1, 2007 through October 10, 2007. |
| • | Incremental amounts payable by Oncor related to income taxes as a result of delivery fee surcharges to its customers related to transition bonds are reimbursed by TCEH. Oncor Holdings’ financial statements reflect a note receivable from TCEH to Oncor of $254 million ($37 million reported as current in trade accounts and other receivables from affiliates) at December 31, 2009 and $289 million ($35 million reported as current in trade accounts and other receivables from affiliates) at December 31, 2008 related to these income taxes. |
| • | As a result of actions taken at the time of the Merger to further ring-fence Oncor, short-term advances from EFH Corp. to Oncor ceased and outstanding amounts were repaid. The average daily balances of short-term advances from parent totaled $42 million for the period January 1, 2007 through October 10, 2007, and the weighted average interest rate for the period was 5.8%. Interest expense incurred on the advances totaled approximately $2 million for the period January 1, 2007 through October 10, 2007. |
| • | An EFH Corp. subsidiary charges Oncor for financial and certain other administrative services at cost. These costs, which are reported in operation and maintenance expenses, totaled $22 million and $24 million for the years ended December 31, 2009 and 2008, respectively, $6 million for the period October 11, 2007 through December 31, 2007 and $20 million for the period January 1, 2007 through October 10, 2007. |
| • | Under Texas regulatory provisions, the trust fund for decommissioning the Comanche Peak nuclear generation facility (reported on TCEH’s balance sheet) is funded by a delivery fee surcharge collected from REPs by Oncor and remitted to TCEH. These trust fund assets are established with the intent to be sufficient to fund the estimated decommissioning liability (also reported on TCEH’s balance sheet). Income and expenses associated with the trust fund and the decommissioning liability recorded by TCEH are offset by a net change in the Oncor and TCEH intercompany receivable/payable, which in turn results in a change in Oncor’s reported net regulatory asset/liability. The regulatory asset of $85 million and $127 million at December 31, 2009 and 2008, respectively, represents the excess of the net decommissioning liability over the trust fund balance. |
| • | Oncor has a 19.5% limited partnership interest, with a carrying value of $3 million and $5 million at December 31, 2009 and 2008, respectively, in an EFH Corp. subsidiary holding principally software-related assets. Equity losses related to this interest are reported in other deductions and totaled $2 million and $4 million for the years ended December 31, 2009 and 2008, respectively, $1 million for the period October 11, 2007 through December 31, 2007 and $2 million for the period January 1, 2007 through October 10, 2007. These losses primarily represent amortization of software assets held by the subsidiary. |
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| • | EFH Corp. files a consolidated federal income tax return and allocates income tax liabilities to Oncor Holdings under a tax sharing agreement substantially as if Oncor Holdings was filing its own income tax returns. Oncor Holdings’ results are included in the consolidated Texas state margin tax return filed by EFH Corp. Oncor Holdings’ amount payable to EFH Corp. related to income taxes totaled $5 million at December 31, 2009, and amount receivable from EFH Corp. related to income taxes, primarily due to timing of payments, totaled $22 million at December 31, 2008. Income tax payments in the year ended December 31, 2009 totaled $19 million to EFH Corp., and Oncor made federal income tax payments totaling $9 million to noncontrolling interests. |
| • | Oncor held cash collateral of $15 million on both December 31, 2009 and 2008 from TCEH related to interconnection agreements for three generation units being developed by TCEH. The collateral is reported in the balance sheet in other current liabilities. |
| • | Certain transmission and distribution utilities in Texas have tariffs in place to assure adequate credit worthiness of any REP to support the REP’s obligation to collect securitization bond-related (transition) charges on behalf of the utility. Under these tariffs, as a result of TCEH’s credit rating being below investment grade, TCEH is required to post collateral support in an amount equal to estimated transition charges over specified time periods. Accordingly, as of December 31, 2009 and 2008, TCEH had posted letters of credit in the amount of $15 million and $13 million, respectively, for Oncor’s benefit. |
| • | At the closing of the Merger, Oncor entered into its current $2 billion revolving credit facility with a syndicate of financial institutions and other lenders. The syndicate includes affiliates of GS Capital Partners. Affiliates of GS Capital Partners (a member of the Sponsor Group) have from time-to-time engaged in commercial banking transactions with Oncor Holdings or its subsidiaries in the normal course of business. |
| • | Affiliates of the Sponsor Group have, and may, sell, acquire or participate in the offerings of debt or debt securities issued by Oncor Holdings or its subsidiaries in open market transactions or through loan syndications. |
See Notes 7, 9, 13 and 17 for information regarding the tax sharing agreement, the accounts receivable securitization program, distributions to Intermediate Holding and the allocation of EFH Corp.’s pension and OPEB costs to Oncor, respectively.
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| 20. | SUPPLEMENTARY FINANCIAL INFORMATION |
Other Income and Deductions
| Successor | Predecessor | |||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||
Other income: | ||||||||||||||
Accretion of adjustment (discount) to regulatory assets due to purchase accounting (Note 2) | $ | 39 | $ | 44 | $ | 10 | $ | — | ||||||
Reversal of exit liabilities recorded in connection with the termination of outsourcing arrangements (see Note 2) | 10 | — | — | — | ||||||||||
Net gain on sale of other properties and investments | — | 1 | 1 | 3 | ||||||||||
Total other income | $ | 49 | $ | 45 | $ | 11 | $ | 3 | ||||||
Other deductions: | ||||||||||||||
Costs related to 2006 cities rate settlement (Note 5) | $ | 2 | $ | 13 | $ | 6 | $ | 20 | ||||||
Professional fees | 5 | 5 | 1 | 5 | ||||||||||
Equity losses in unconsolidated affiliate (Note 19) | 2 | 4 | 1 | 2 | ||||||||||
Expenses related to canceled InfrastruX Energy services joint venture (a) | — | — | — | 3 | ||||||||||
Other | 5 | 3 | — | — | ||||||||||
Total other deductions | $ | 14 | $ | 25 | $ | 8 | $ | 30 | ||||||
| (a) | Consists of previously deferred costs arising from operational activities to transition to the joint venture arrangement, which was canceled in connection with the Merger. |
Major Customers
Distribution revenues from TCEH represented 38% and 39% of total operating revenues for the years ended December 31, 2009 and 2008, respectively, 39% for the period October 11, 2007 through December 31, 2007 and 42% for the period January 1, 2007 through October 10, 2007. Revenues from subsidiaries of one nonaffiliated REP collectively represented 14% and 16% of total operating revenues for the years ended December 31, 2009 and 2008, respectively, 15% for the period October 11, 2007 through December 31, 2007 and 16% for the period January 1, 2007 through October 10, 2007. No other customer represented 10% or more of total operating revenues.
Interest Expense and Related Charges
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Interest | $ | 338 | $ | 314 | $ | 70 | $ | 242 | ||||||||||
Amortization of fair value debt discounts resulting from purchase accounting | 3 | 3 | — | — | ||||||||||||||
Amortization of debt issuance costs and discounts | 7 | 5 | 1 | 7 | ||||||||||||||
Allowance for funds used during construction — capitalized interest portion | (2 | ) | (6 | ) | (1 | ) | (7 | ) | ||||||||||
Total interest expense and related charges | $ | 346 | $ | 316 | $ | 70 | $ | 242 | ||||||||||
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Property, Plant and Equipment
| December 31, 2009 | December 31, 2008 | |||||
Assets in service: | ||||||
Distribution | $ | 8,778 | $ | 8,429 | ||
Transmission | 3,917 | 3,626 | ||||
Other assets | 579 | 477 | ||||
Total | 13,274 | 12,532 | ||||
Less accumulated depreciation | 4,444 | 4,158 | ||||
Net of accumulated depreciation | 8,830 | 8,374 | ||||
Construction work in progress | 321 | 213 | ||||
Held for future use | 23 | 19 | ||||
Property, plant and equipment — net | $ | 9,174 | $ | 8,606 | ||
Depreciation expense as a percent of average depreciable property approximated 3.1% for 2009 and 2.8% for 2008 and 2007.
Intangible Assets
Intangible assets other than goodwill reported in the balance sheet are comprised of the following:
| As of December 31, 2009 | As of December 31, 2008 | |||||||||||||||||
| Gross Carrying Amount | Accumulated Amortization | Net | Gross Carrying Amount | Accumulated Amortization | Net | |||||||||||||
Intangible assets subject to amortization included in property, plant and equipment: | ||||||||||||||||||
Land easements | $ | 188 | $ | 72 | $ | 116 | $ | 184 | $ | 69 | $ | 115 | ||||||
Capitalized software | 240 | 104 | 136 | 145 | 80 | 65 | ||||||||||||
Total | $ | 428 | $ | 176 | $ | 252 | $ | 329 | $ | 149 | $ | 180 | ||||||
Aggregate amortization expense for intangible assets totaled $27 million and $19 million for the years ended December 31, 2009 and 2008, respectively, $3 million for the period October 11, 2007 through December 31, 2007 and $11 million for the period January 1, 2007 through October 10, 2007. At December 31, 2009, the weighted average remaining useful lives of capitalized land easements and software were 67 years and 6 years, respectively. The estimated aggregate amortization expense for each of the next five fiscal years is as follows:
Year | Amortization Expense | ||
2010 | $ | 32 | |
2011 | 23 | ||
2012 | 21 | ||
2013 | 21 | ||
2014 | 21 | ||
At December 31, 2009 and 2008, goodwill of $4.1 billion was reported on the balance sheet. None of this goodwill is being deducted for tax purposes. This balance is net of the $860 million goodwill impairment charge recorded in the fourth quarter of 2008. No other impairments have been recorded since the Merger. See Note 2 for discussion of financial statement effects of the Merger, and Note 3 for discussion of the goodwill impairment.
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Other Noncurrent Liabilities and Deferred Credits
The other noncurrent liabilities and deferred credits balance consists of the following:
| Successor | ||||||
| December 31, 2009 | December 31, 2008 | |||||
Retirement plan and other employee benefits | $ | 1,343 | $ | 1,115 | ||
Liabilities related to subsidiary tax sharing agreement | 321 | 299 | ||||
Uncertain tax positions (including accrued interest) | 91 | 144 | ||||
Nuclear decommissioning cost under-recovery (a) | 85 | 127 | ||||
Other | 39 | 35 | ||||
Total other noncurrent liabilities and deferred credits | $ | 1,879 | $ | 1,720 | ||
| (a) | Represents intercompany payable to TCEH offset in Oncor’s net reported regulatory asset/liability. See Note 8. |
Liabilities Related to Subsidiary Tax Sharing Agreement —Amount represents the previously recorded net deferred tax liabilities of Oncor related to the noncontrolling interests. Upon the sale of noncontrolling interests in Oncor (see Note 14), Oncor became a partnership for US federal income tax purposes, and the temporary differences which gave rise to the deferred taxes will, over time, become taxable to the noncontrolling interests. Under a tax sharing agreement among Oncor and its equity holders, Oncor reimburses its equity holders for federal income taxes as the partnership earnings become taxable to such holders. Accordingly, as the temporary differences become taxable, the equity holders will be reimbursed by Oncor. In the unlikely event such amounts are not reimbursed under the tax sharing agreement, it is probable they would be refunded to rate payers. The net changes in the liability for the year ended December 31, 2009 totaling $22 million reflected changes in temporary differences.
Supplemental Cash Flow Information
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Cash payments: | ||||||||||||||||||
Interest paid | $ | 337 | $ | 284 | $ | 72 | $ | 240 | ||||||||||
Capitalized interest | (2 | ) | (6 | ) | (1 | ) | (7 | ) | ||||||||||
Interest (net of amounts capitalized) | 335 | 278 | 71 | 233 | ||||||||||||||
Income taxes | 28 | 65 | 26 | 106 | ||||||||||||||
Noncash investing and financing activities: | ||||||||||||||||||
Noncash construction expenditures (a) | 61 | 49 | 70 | 25 | ||||||||||||||
Noncash capital contribution related to settlement of certain income taxes payable (b) | 50 | — | — | — | ||||||||||||||
Noncash distribution of investment to parent | — | 24 | — | — | ||||||||||||||
Noncash contribution related to incentive compensation plans | — | — | 28 | — | ||||||||||||||
Noncash capital contribution from Texas Holdings | — | — | 12 | — | ||||||||||||||
| (a) | Represents end-of-period accruals. |
| (b) | Reflects noncash settlement of certain income taxes payable arising as a result of the sale of noncontrolling interests in Oncor. |
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| 21. | CONDENSED FINANCIAL INFORMATION OF REGISTRANT |
ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF INCOME (LOSS)
(millions of dollars)
| Successor | Predecessor | ||||||||||||||
| Year Ended December 31, 2009 | Year Ended December 31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | ||||||||||||
Income tax benefit | $ | — | $ | 4 | $ | — | $ | — | |||||||
Equity in earnings (losses) of subsidiary | 256 | (327 | ) | 64 | 263 | ||||||||||
Net income (loss) | $ | 256 | $ | (323 | ) | $ | 64 | $ | 263 | ||||||
See Notes to Financial Statements.
CONDENSED STATEMENTS OF CASH FLOWS
(millions of dollars)
| Successor | Predecessor | |||||||||||||||||
| Year Ended December 31, 2009 | Year Ended December��31, 2008 | Period from October 11, 2007 through December 31, 2007 | Period from January 1, 2007 through October 10, 2007 | |||||||||||||||
Cash flows — operating activities: | ||||||||||||||||||
Net income | $ | 256 | $ | (323 | ) | $ | 64 | $ | 263 | |||||||||
Adjustments to reconcile net income to cash provided by operating activities: | ||||||||||||||||||
Equity in (earnings) losses of subsidiaries | (256 | ) | 327 | (64 | ) | (263 | ) | |||||||||||
Deferred income taxes — net | (50 | ) | (4 | ) | — | — | ||||||||||||
Net changes in operating assets and liabilities | 266 | 331 | — | — | ||||||||||||||
Cash provided by operating activities | 216 | 331 | — | — | ||||||||||||||
Cash flows — financing activities: | ||||||||||||||||||
Proceeds from sale of noncontrolling interests, net of transaction costs (Note 14) | — | 1,253 | — | — | ||||||||||||||
Distribution to parent of equity sale net proceeds | — | (1,253 | ) | — | — | |||||||||||||
Distributions to parent | (216 | ) | (330 | ) | — | — | ||||||||||||
Cash used in financing activities | (216 | ) | (330 | ) | — | — | ||||||||||||
Cash flows — investing activities: | ||||||||||||||||||
Cash used in investing activities | — | — | — | — | ||||||||||||||
Net change in cash and cash equivalents | — | 1 | — | — | ||||||||||||||
Cash and cash equivalents — beginning balance | 1 | — | — | — | ||||||||||||||
Cash and cash equivalents — ending balance | $ | 1 | $ | 1 | $ | — | $ | — | ||||||||||
See Notes to Financial Statements.
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ONCOR ELECTRIC DELIVERY HOLDINGS COMPANY LLC
CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(millions of dollars)
| Successor | ||||||
| December 31, 2009 | December 31, 2008 | |||||
| ASSETS | ||||||
Current assets: | ||||||
Cash and cash equivalents | $ | 1 | $ | 1 | ||
Income taxes receivable from EFH Corp. | 3 | 1 | ||||
Other current assets | 2 | 2 | ||||
Total current assets | 6 | 4 | ||||
Investments | 5,804 | �� | 5,741 | |||
Total assets | $ | 5,810 | $ | 5,745 | ||
| LIABILITIES AND MEMBERSHIP INTEREST | ||||||
Current liabilities: | ||||||
Other current liabilities | $ | 3 | $ | — | ||
Total current liabilities | 3 | — | ||||
Accumulated deferred income taxes | 91 | 141 | ||||
Other noncurrent liabilities and deferred credits | 321 | 299 | ||||
Total liabilities | 415 | 440 | ||||
Membership interest | 5,395 | 5,305 | ||||
Total liabilities and membership interest | $ | 5,810 | $ | 5,745 | ||
See Notes to Financial Statements.
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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, statements of income (loss) and cash flows present results of operations and cash flows of Oncor Holdings for periods subsequent to the Merger, at which time Oncor Holdings was formed. Oncor Holdings, which is a Delaware limited liability company wholly-owned by Intermediate Holding, is the holding company for approximately 80% of the membership interests in Oncor as of December 31, 2009. The financial statements reflect the application of purchase accounting for the Merger at Oncor. Certain information and footnote disclosures normally included in financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules of the SEC. Because the unconsolidated condensed financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with Oncor Holdings’ consolidated financial statements and Notes 1 through 20. Oncor Holdings’ subsidiaries have been accounted for under the equity method. All dollar amounts in the financial statements and tables in the notes are stated in millions of US dollars unless otherwise indicated. The predecessor to Oncor Holdings is Oncor. Accordingly, Predecessor amounts in the accompanying unconsolidated condensed statements of income (loss) and cash flows reflect Oncor’s results accounted for under the equity method. The financial statements of Oncor are presented as the Predecessor of Oncor Holdings’ historical consolidated financial statements and related notes.
Distribution Restrictions
While there are no direct restrictions on Oncor Holdings’ ability to distribute its net income that are currently material, substantially all of Oncor Holdings’ net income is derived from Oncor. The boards of directors of each of Oncor and Oncor Holdings, which are composed of a majority of independent directors, can withhold distributions to the extent the boards determine that it is necessary to retain such amounts to meet expected future requirements of Oncor and/or Oncor Holdings. For the period beginning October 11, 2007 and ending December 31, 2012, distributions paid by Oncor (other than distributions of the proceeds of any issuance of limited liability company units) are limited by the Limited Liability Company Agreement to an amount not to exceed Oncor’s net cumulative income determined in accordance with GAAP, as adjusted by applicable orders of the PUCT. Such adjustments include deducting the $72 million ($46 million after tax) one-time refund to customers in September 2008 and deducting funds spent as part of the $100 million commitment for additional demand-side management or other energy efficiency initiatives (see Note 4) of which $22 million ($14 million after tax) has been spent through December 31, 2009, neither of which impacted net income due to purchase accounting, and removing the effect of the $860 million goodwill impairment charge from fourth quarter 2008 net income available for distribution. The goodwill impairment charge and refund are described in Notes 3 and 4, respectively. Distributions are further limited by Oncor’s required regulatory capital structure, as determined by the PUCT, to be at or below the assumed debt-to-equity ratio established periodically by the PUCT for ratemaking purposes, which is currently set at 60% debt to 40% equity. For 2009, $35 million of net income was restricted from being used to make distributions on membership interests. The net proceeds of $1.253 billion received from the 2008 sale of equity interests to Texas Transmission and certain members of Oncor’s management and board of directors were excluded from these distribution limitations.
On February 11, 2010, Oncor’s board of directors declared a cash distribution of between $34 million and $41 million to be paid to Oncor Holdings on February 19, 2010. During 2009 and 2008, Oncor’s board of directors declared, and Oncor paid, cash distributions to Oncor Holdings totaling $216 million and $330 million, respectively. No dividends were received for the period from October 11, 2007 through December 31, 2007.
The net proceeds of $1.253 billion from Oncor’s sale of equity interests in November 2008 were distributed to Intermediate Holding and ultimately to EFH Corp.
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