Edison International 10-K 2010
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Commission File Number 1-9936
Securities registered pursuant to Section 12(b) of the Act:
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 þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No þ
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 þ No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, 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 þ No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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. þ
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 the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check One):
Large Accelerated Filer þ Accelerated Filer o Non-accelerated Filer o Smaller Reporting Company o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
The aggregate market value of registrant's voting stock held by non-affiliates was approximately $10.25 billion on or about June 30, 2009, based upon prices reported on the New York Stock Exchange. As of February 25, 2010, there were 325,811,206 shares of Common Stock outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the following documents listed below have been incorporated by reference into the parts of this report so indicated.
Table of Contents
This Annual Report on Form 10-K contains "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect Edison International's current expectations and projections about future events based on Edison International's knowledge of present facts and circumstances and assumptions about future events and include any statement that does not directly relate to a historical or current fact. Other information distributed by Edison International that is incorporated in this report, or that refers to or incorporates this report, may also contain forward-looking statements. In this report and elsewhere, the words "expects," "believes," "anticipates," "estimates," "projects," "intends," "plans," "probable," "may," "will," "could," "would," "should," and variations of such words and similar expressions, or discussions of strategy or of plans, are intended to identify forward-looking statements. Such statements necessarily involve risks and uncertainties that could cause actual results to differ materially from those anticipated. Some of the risks, uncertainties and other important factors that could cause results to differ from those currently expected, or that otherwise could impact Edison International, include, but are not limited to:
See "Risk Factors" in Part I, Item 1A of this report for additional information on risks and uncertainties that could cause results to differ from those currently expected or that otherwise could impact Edison International or its subsidiaries.
Additional information about risks and uncertainties, including more detail about the factors described in this report, is contained throughout this report. Readers are urged to read this entire report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect Edison International's business. Forward-looking statements speak only as of the date they are made and Edison International is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International with the U.S. Securities and Exchange Commission.
Except when otherwise stated, references to each of Edison International, SCE, EMG, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to "Edison International (parent)" or "parent company" mean Edison International on a stand-alone basis, not consolidated with its subsidiaries.
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
Edison International was incorporated on April 20, 1987, under the laws of the State of California for the purpose of becoming the parent holding company of Southern California Edison Company ("SCE"), a California public utility corporation, Edison Mission Energy ("EME"), an independent power producer, and Edison Capital, an infrastructure finance company. Beginning in 2006, EME and Edison Capital have been presented on a consolidated basis as Edison Mission Group Inc. ("EMG"), reflecting the integration of management and personnel at EME and Edison Capital. As a holding company, Edison International's progress and outlook are dependent on developments at its operating subsidiaries.
At December 31, 2009, Edison International and its subsidiaries had an aggregate of 19,244 full-time employees, of which 53 were employed directly by Edison International. The principal executive offices of Edison International are located at 2244 Walnut Grove Avenue, P.O. Box 976, Rosemead, California 91770, and the telephone number is (626) 302-2222.
Edison International makes available on its investor website, www.edisoninvestor.com, its Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statement and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act, as soon as reasonably practicable after Edison International electronically files such material with, or furnishes it to, the SEC. Such reports are also available on the SEC's internet website at www.sec.gov. The information contained on, or connected to, the Edison investor website is not incorporated by reference into this report.
Edison International has three business segments for financial reporting purposes: an electric utility operation segment (SCE), a competitive power generation segment (EME), and a financial services provider segment (Edison Capital). Financial information about these segments and about geographic areas, for fiscal years 2009, 2008, and 2007, is contained in "Item 8. Edison International Notes to Consolidated Financial StatementsNote 16. Business Segments" and incorporated herein by this reference. Additional information about each of these business segments appears below under the headings "Southern California Edison Company" and "Edison Mission Group Inc."
SCE is an investor-owned public utility primarily engaged in the business of supplying electricity to a 50,000-square-mile area of central, coastal and southern California, excluding the City of Los Angeles and certain other cities. The SCE service territory includes over 400 cities and communities and a population of more than 13 million people. In 2009, SCE's total operating revenue was derived as follows: 42% commercial customers, 39% residential customers, 6% industrial customers, 2% resale sales, 6% public authorities, and 5% agricultural and other customers. SCE had 17,348 full-time employees at December 31, 2009. SCE's operating revenue was approximately $10 billion in 2009.
SCE files separately an Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, Proxy Statement and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act, as soon as reasonably practicable after SCE electronically files such material with, or furnishes it to, the SEC. Such reports are also available at www.edisoninvestor.com or on the SEC's internet website at www.sec.gov. The information contained on, or connected to, the Edison investor website is not incorporated by reference into this report.
EMG is the holding company for its principal wholly owned subsidiaries, EME and Edison Capital. EME is a holding company with subsidiaries and affiliates engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME also conducts hedging and energy trading activities in competitive power markets through its Edison Mission Marketing & Trading, Inc. ("EMMT") subsidiary. At December 31, 2009, EME and its subsidiaries employed 1,843 people.
EME's subsidiaries or affiliates have typically been formed to own full or partial interests in one or more power plants and ancillary facilities, with each plant or group of related plants being individually referred to by EME as a project. EME's operating projects primarily consist of coal-fired generating facilities, natural gas-fired generating facilities and renewable energy facilities (primarily wind projects and one biomass project). As of December 31, 2009, EME's subsidiaries and affiliates owned or leased interests in 39 operating projects with an aggregate net physical capacity of 11,269 MW of which EME's pro rata share was 10,072 MW. At December 31, 2009, EME's subsidiaries and affiliates also owned two wind projects under construction totaling 390 MW of net generating capacity. EME's consolidated operating revenue in 2009 was approximately $2.4 billion.
EME files separately an Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act, as soon as reasonably practicable after EME electronically files such material with, or furnishes it to, the SEC. Such reports are also available www.edisoninvestor.com or on the SEC's internet website at www.sec.gov. The information contained on, or connected to, the Edison investor website is not incorporated by reference into this report.
Edison Capital has investments worldwide in energy and infrastructure projects, including power generation, electric transmission and distribution, transportation, and telecommunications. Edison Capital also has investments in affordable housing projects located throughout the United States. At the present time, no new investments are expected to be made by Edison Capital and the focus will be on managing the existing investment portfolio.
Edison International and its subsidiaries are subject to extensive regulation. As a public utility holding company, Edison International is subject to the Public Utility Holding Company Act. The PUHCA primarily obligates Edison International and its utility subsidiaries to provide access to their books and records to the FERC and the CPUC for ratemaking purposes.
SCE's rates and operations are subject to extensive regulation by the CPUC, FERC, NRC, CEC, and CAISO. See "Southern California Edison Company Regulation of SCE." EME's operating projects are also subject to energy, environmental and other governmental laws and regulations at the federal, state and local levels, and EME is additionally subject to the market rules, procedures, and protocols of the markets in which it participates. See "Edison Mission Group Inc. Regulation." Both SCE and EME are also subject to the reliability standards for the bulk power system required by the North American Electric Reliability Corporation ("NERC").
Edison International is not a public utility under the laws of the State of California or any other state and is not subject to regulation as such by the CPUC or any similar agency. See "Southern California Edison CompanyRegulation of SCE" below for a description of the regulation of SCE by the CPUC. The 1988 CPUC decision authorizing SCE to reorganize into a holding company structure, however, contains certain conditions, which, among other things: (1) ensure CPUC access to books and records of Edison International and its affiliates which relate to transactions with SCE; (2) require Edison International and its subsidiaries to employ accounting and other procedures and controls to ensure full review by the CPUC and to protect against subsidization of nonutility activities by SCE's customers; (3) require that all transfers of market, technological, or similar data from SCE to Edison International or its affiliates be made at market value; (4) preclude SCE from guaranteeing any obligations of Edison International without prior written consent from the CPUC; (5) provide for royalty payments to be paid by Edison International or its subsidiaries in connection with the transfer of product rights, patents, copyrights, or similar legal rights from SCE; and (6) prevent Edison International and its subsidiaries from providing certain facilities and equipment to SCE except through competitive bidding. In addition, the decision provides that SCE shall maintain a balanced capital structure in accordance with CPUC decisions, that SCE's dividend policy shall continue to be established by SCE's Board of Directors as though SCE were a stand-alone utility company, and that the capital requirements of SCE, as deemed to be necessary to meet SCE's service obligations, shall receive first priority from the Boards of Directors of Edison International and SCE. The CPUC has also promulgated Affiliate Transaction Rules, which contain similar restrictions that apply to Edison International, as a holding company.
Financial information for geographic areas for Edison International can be found in "Item 8. Edison International Notes to Consolidated Financial StatementsNote 16. Business Segments andNote 17. Acquisitions."
SCE's retail operations are subject to regulation by the CPUC. The CPUC has the authority to regulate, among other things, retail rates, energy purchases on behalf of retail customers, rate of return, rates of depreciation, issuance of securities, disposition of utility assets and facilities, oversight of nuclear decommissioning, and aspects of the construction, planning and project site identification of the electricity transmission system.
The CPUC has established resource adequacy requirements, which require SCE to procure adequate electricity to meet its expected customer needs on both a system-wide and a local basis. SCE would be subject to penalties if it failed to meet the requirements. SCE complied with the resource adequacy requirements in 2009 and expects to comply in 2010.
California law requires SCE to increase its procurement of energy from renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than December 31, 2010 or such later date as flexible compliance requirements may permit. Under the CPUC's current rules, the maximum penalty for inability to achieve renewable procurement targets is $25 million per year. SCE's ability to meet the RPS target depends largely on the ability of third parties to meet contractual obligations to deliver power to SCE. Flexible compliance rules, such as banking of past surplus and earmarking of future deliveries from executed contracts, are also available. SCE does not believe it will be assessed penalties for 2009 or prior years and cannot predict whether it will be assessed penalties for future years.
SCE's wholesale operations (including sales of electricity into the wholesale markets) are subject to regulation by the FERC. The FERC has the authority to regulate wholesale rates as well as other matters, including unbundled transmission service pricing, accounting practices, and licensing of hydroelectric projects.
The construction, planning, and project site identification of SCE's power plants within California are subject to the jurisdiction of the California Energy Commission ("CEC") (for plants 50 MW or greater). The CEC is responsible for forecasting future energy needs. These forecasts are used by the CPUC in determining the adequacy of SCE's electricity procurement plans. California law prohibits the CEC from siting or permitting a new nuclear power plant in California until it finds a federally approved and demonstrated method for the disposal of nuclear waste.
SCE is subject to the jurisdiction of the U.S. Nuclear Regulatory Commission ("NRC") with respect to its San Onofre and Palo Verde Nuclear Generating Stations. NRC requirements govern the granting, amendment, and extension of licenses for the construction and operation of nuclear power plants and subject those power plants to continuing oversight, inspection, and performance assessment with respect to plant operation and related activities.
San Onofre is currently addressing a number of regulatory and performance issues. The NRC is requiring SCE to take actions to provide greater assurance of compliance by San Onofre personnel with applicable NRC requirements and procedures. SCE is currently implementing plans to address the identified issues. The NRC has continued to affirm that San Onofre has been operated and is being operated safely; however, the cumulative impact of these regulatory and performance issues is an increase in management focus and other resources applied at San Onofre.
Information about nuclear decommissioning can be found in "Item 8. Edison International Notes to Consolidated Financial StatementsNote 1. Summary of Significant Accounting Policies andNote 6. Commitments and Contingencies." Information about nuclear insurance can be found in "Item 8. Edison International Notes to Consolidated Financial StatementsNote 6. Commitments and Contingencies."
The construction, planning and project site identification of SCE's transmission lines and substation facilities require the approval of many governmental agencies and compliance with various laws. These agencies include utility regulatory commissions such as the CPUC and other state regulatory agencies depending on the project location; the Independent System Operator ("ISO"), and other environmental, land management and resource agencies such as the Bureau of Land Management, the U.S. Forest Service, and the California Department of Fish and Game; and Regional Water Quality Control Boards. In addition, to the extent that SCE transmission line projects pass through lands owned or controlled by Native American tribes, consent and approval from the affected tribes and the Bureau of Indian Affairs will also be necessary for the project to proceed.
SCE is subject to CPUC and FERC affiliate transaction rules and compliance plans governing the relationship between SCE and its affiliates.
SCE sells electricity to retail customers at rates authorized by the CPUC. SCE sells transmission service and wholesale power at rates authorized by the FERC.
Base rates authorized by the CPUC and the FERC are intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation,
transmission and distribution facilities (or "rate base"). These base rates provide for recovery of operations and maintenance costs, capital-related carrying costs (depreciation, taxes and interest) and a return or profit, on a forecast basis.
Base rates for SCE's generation and distribution functions provide a rate of return and are authorized by the CPUC through triennial GRC proceedings. The CPUC sets an annual revenue requirement for the base year which is made up of the carrying cost on capital investment (depreciation, return and taxes), plus the authorized level of operation and maintenance expense. The return is established by multiplying an authorized rate of return, determined in the separate cost of capital proceedings (as discussed below), by the generation and distribution rate base. In the GRC proceedings, the CPUC also approves capital spending on a forecast basis. Adjustments to the revenue requirement for the remaining two years of a typical three-year GRC cycle are requested, based on criteria established in the GRC proceeding, which generally, among other items, include annual allowances for escalation in operation and maintenance costs, forecasted changes in capital-related investments and the timing and number of expected nuclear refueling outages. SCE's most recent GRC decision for the 2009-2011 period was issued in March 2009 and was effective as of January 1, 2009. SCE expects to begin proceedings for the 2012 GRC in the third quarter of 2010. As part of the GRC, the CPUC has authorized a revenue decoupling mechanism, which allows for the difference between the revenue authorized and the actual volume of electricity sales to be collected from or refunded to ratepayers. Accordingly, SCE does not bear the volumetric risk related to electricity sales.
The CPUC regulates SCE's capital structure and authorized rate of return. SCE's current authorized capital structure is 48% common equity, 43% long-term debt and 9% preferred equity. SCE's current authorized cost of capital consists of: cost of long-term debt of 6.22%, authorized cost of preferred equity of 6.01% and authorized return on common equity of 11.5%. In 2008, the CPUC approved a multi-year cost of capital mechanism, which allows for annual adjustments if certain thresholds are reached. SCE's earnings may be impacted when actual financing costs are above or below its authorized costs for long-term debt and preferred equity financings.
Base rates for SCE's transmission functions provide a rate of return and are authorized by the FERC, in periodic proceedings that are similar to the CPUC GRC proceeding. Requested rate changes at the FERC are generally implemented before final approval of the application, with revenue collected prior to a final FERC decision being subject to refund. FERC-approved base rate revenues that vary from forecast are not subject to balancing account mechanisms, or otherwise recoverable or refundable and will therefore impact earnings.
Cost-recovery mechanisms allow SCE to recover its costs, but do not allow a return or profit. These mechanisms are used to recover SCE's costs of fuel, purchased-power, demand-side management programs, nuclear decommissioning, public purpose programs, certain operation
and maintenance expenses, and depreciation expense related to certain projects. Although the CPUC authorizes balancing account mechanisms for such costs to refund or recover any differences between forecasted and actual costs, under- or over-collections in these balancing accounts do impact cash flows and can build rapidly.
The CPUC also uses a mechanism known as a "balancing account" to eliminate the effect on earnings that differences in revenue resulting from actual and forecast electricity sales may have. Under this mechanism, the difference in revenue between actual and forecast electricity sales is recovered from or refunded to ratepayers and therefore does not impact SCE's earnings.
SCE's balancing account for fuel and power procurement-related costs is established under the Energy Resource Recovery Account ("ERRA") Mechanism. SCE files annual forecasts of the costs that it expects to incur during the following year and sets rates using forecasts. The CPUC has established a "trigger" mechanism for the ERRA balancing account that allows for a rate adjustment if the balancing account over-collection or under-collection exceeds 5% of SCE's prior year's generation revenue.
The majority of costs eligible for recovery through cost-recovery rates are subject to CPUC reasonableness reviews, and thus could negatively impact earnings and cash flows if found to be unreasonable and disallowed.
The CPUC has adopted an Energy Efficiency Risk/Reward Incentive Mechanism which allows for both financial incentives and economic penalties based on SCE's performance toward meeting goals set by the CPUC for energy efficiency. Under this mechanism, SCE has the opportunity to earn an incentive if it achieves 85% or more of its energy efficiency goals for the three year period. Economic penalties would be imposed in the event SCE achieves less than 65% of its goals. The mechanism allows for two annual progress payments, subject to holdback percentages, for progress towards meeting the goals and a third payment for final performance on the goals, which includes the payment of any holdbacks. SCE may retain the first and second progress payments as long as it meets a minimum of 65% of the goals. If SCE does not meet the 65% level, the amount of the progress payments and economic penalties would be deducted from future incentive payments. Both incentives and economic penalties for each three-year period are capped at $200 million.
In January 2009, the CPUC issued a new rulemaking intended to review the framework of the Energy Efficiency Risk/Reward Incentive Mechanism. The CPUC has yet to release a Decision on a new framework.
As a result of the California energy crisis, in 2001 the California Department of Water Resources ("CDWR") entered into contracts to purchase power for sale at cost directly to SCE's retail customers and issued bonds to finance those power purchases. The CDWR's total statewide power charge and bond charge revenue requirements are allocated by the CPUC among the customers of the Investor-Owned Utilities. SCE bills and collects from its customers the costs of power purchased and sold by the CDWR, CDWR bond-related charges
and direct access exit fees. The CDWR-related charges and a portion of direct access exit fees that are remitted directly to the CDWR are not recognized as electric utility revenue by SCE and therefore have no impact on SCE's earnings; however, they do impact customer rates.
Because SCE is an electric utility company operating within a defined service territory pursuant to authority from the CPUC, SCE faces competition only to the extent that federal and California laws permit other entities to provide electricity and related services to customers within SCE's service territory. While California law provides only limited opportunities for customers to choose to purchase power directly from an energy service provider other than SCE, a California law was adopted in 2009 that permits a limited, phased-in expansion of customer choice (direct access) for nonresidential customers. SCE also faces some competition from cities and municipal districts that create municipal utilities or community choice aggregators. In addition, customers may install their own on-site power generation facilities.
Competition with SCE is conducted mainly on the basis of price, as customers seek the lowest cost power available. The effect of competition on SCE generally is to reduce the number of customers purchasing power from SCE, but those customers typically continue to utilize and pay for SCE's transmission and distribution services.
In the area of transmission infrastructure, SCE may experience increased competition from merchant transmission providers.
SCE obtains the power needed to serve its customers from its generating facilities and from purchases from qualifying facilities ("QFs"), independent power producers, renewable power producers, the CAISO, and other utilities. In addition, power is provided to SCE's customers through purchases by the CDWR under contracts with third parties. Sources of power to serve SCE's customers during 2009 were approximately: 44% purchased power; 23% CDWR; and 33% SCE-owned generation.
SCE requires natural gas to meet contractual obligations for power tolling agreements (power contracts in which SCE has agreed to provide the natural gas needed for generation under those power contracts) and to serve demand for gas at Mountainview and SCE's peaker plants, which are supplemental plants that only operate when demand for power is high. All of the physical gas purchased by SCE in 2009 was purchased through competitive bidding.
For San Onofre Units 2 and 3, contractual arrangements are in place covering 100% of the projected nuclear fuel requirements through the years indicated below:
For Palo Verde, contractual arrangements are in place covering 100% of the projected nuclear fuel requirements through the years indicated below:
Information about Spent Nuclear Fuel appears in "Item 8. Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies."
On January 1, 2005, SCE and the other Four Corners participants entered into a Restated and Amended Four Corners Fuel Agreement with the BHP Navajo Coal Company, under which coal will be supplied to Four Corners Units 4 and 5 until July 6, 2016. The Restated and Amended Agreement contains an option to extend for not less than five additional years or more than 15 years.
In California and other states, wholesale energy markets exist through which competing electricity generators offer their electricity output to electricity retailers. Each state's wholesale electricity market is generally operated by its state ISO or a regional RTO. California's wholesale electricity market is operated by the CAISO. In 2006, the CAISO began its Market Redesign and Technology Upgrade ("MRTU") program to redesign and upgrade the wholesale energy market across its controlled grid. The MRTU market design allows the CAISO to schedule power in hourly increments with hourly prices through a real-time and day-ahead market that combines energy, ancillary services, unit commitment and congestion management. These MRTU features became effective in March 2009 and SCE began participating in the day-ahead and real-time markets for the sale of its generation and purchases of its load requirements.
The MRTU structure uses a nodal locational pricing model, which sets wholesale electricity prices at 3,000 different system points (nodes) that reflect local generation and delivery costs, as opposed to the previous system of three broad zonal prices. Generally, SCE schedules its
electricity generation to serve its load but when it has excess generation or the market price of power is more economic than its own generation, SCE may sell power from utility-owned generation assets and existing power procurement contracts on, or buy generation and/or ancillary services to meet its load requirements from, the day-ahead market. SCE will offer to buy its generation at nodes near the source of the generation, but will take delivery at nodes throughout SCE's service territory. Congestion may occur when available energy cannot be delivered to all loads due to transmission constraints, which results in transmission congestion charges and differences in prices at various nodes. The CAISO also offers congestion revenue rights or CRRs, a commodity that entitles the holder to receive (or pay) the value of transmission congestion between specific nodes, acting as an economic hedge against transmission congestion charges.
SCE supplies electricity to its customers through extensive transmission and distribution networks. Its transmission facilities, which are located primarily in California but also in Nevada and Arizona, deliver power from generating sources to the distribution network and consist of 33 kV, 55 kV, 66 kV, 115 kV, 161 kV; 220 kV and 500 kV lines; and 893 substations. SCE's distribution system, which takes power from substations to customers, includes over 70,000 circuit miles of overhead lines, 43,500 circuit miles of underground lines, 1.46 million poles, over 720 distribution substations, approximately 715,600 transformers, and 813,000 area lights and streetlights, all of which are located in California.
SCE owns the following generating facilities (and operates all of these facilities except Palo Verde and Four Corners, which are operated by Arizona Public Service Company ("APS")):
San Onofre, Four Corners, certain of SCE's substations, and portions of its transmission, distribution and communication systems are located on lands owned by the United States or others under licenses, permits, easements or leases, or on public streets or highways pursuant to franchises. Certain of the documents evidencing such rights obligate SCE, under specified circumstances and at its expense, to relocate such transmission, distribution, and communication facilities located on lands owned or controlled by federal, state, or local governments.
Thirty-one of SCE's 36 hydroelectric plants and related reservoirs, are located in whole or in part on U.S.-owned lands pursuant to 30- to 50-year FERC licenses that expire at various times between 2010 and 2040. Such licenses impose numerous restrictions and obligations on SCE, including the right of the United States to acquire projects upon payment of specified compensation. When existing licenses expire, the FERC has the authority to issue new licenses to third parties that have filed competing license applications, but only if their license
application is superior to SCE's and then only upon payment of specified compensation to SCE. New licenses issued to SCE are expected to contain more restrictions and obligations than the expired licenses because laws enacted since the existing licenses were issued require the FERC to give environmental objectives greater consideration in the licensing process.
Substantially all of SCE's properties are subject to the lien of a trust indenture securing first and refunding mortgage bonds, of which approximately $6.4 billion in principal amount was outstanding on February 26, 2010.
SCE's rights in Four Corners, which is located on land of the Navajo Nation under an easement from the United States and a lease from the Navajo Nation, may be subject to possible defects. These defects include possible conflicting grants or encumbrances not ascertainable because of the absence of, or inadequacies in, the applicable recording law and record systems of the Bureau of Indian Affairs and the Navajo Nation, the possible inability of SCE to resort to legal process to enforce its rights against the Navajo Nation without Congressional consent, the possible impairment or termination under certain circumstances of the easement and lease by the Navajo Nation, Congress, or the Secretary of the Interior, and the possible invalidity of the trust indenture lien against SCE's interest in the easement, lease, and improvements on Four Corners.
SCE has property and casualty insurance policies, which include excess liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations.
Severe wildfires in California have given rise to large damage claims against California utilities. Additionally, California law includes a doctrine of inverse condemnation that imposes strict liability (including liability for a claimant's attorneys' fees) for fire damage caused to private property by a utility's electric facilities that serve the public. These damage claims and the related doctrine may affect SCE's liability insurance levels and cost. On September 1, 2009, SCE renewed its insurance coverage, which included coverage for wildfire liabilities up to a reduced limit of $500 million (with an increased self-insured retention of $10 million per wildfire occurrence). Various coverage limitations within the policies that make up the insurance coverage could result in substantially higher self-insured costs in the event of multiple wildfire occurrences during the policy period (September 1, 2009 to August 31, 2010). SCE may experience further coverage reductions and/or increased insurance costs in future years. No assurance can be given that future losses will not exceed the limits of SCE's insurance coverage.
For a discussion of the seasonality of electric utility revenues, see "Electric Utility Results of OperationsSupplemental Operating Revenue Information" in the MD&A.
The Federal Power Act ("FPA") grants the FERC exclusive jurisdiction over the rates, terms and conditions of wholesale sales of electricity and transmission services in interstate commerce (other than transmission that is "bundled" with retail sales), including ongoing, as well as initial, rate jurisdiction. This jurisdiction allows the FERC to revoke or modify previously approved rates after notice and opportunity for hearing. These rates may be based on a cost-of-service approach or, in geographic and product markets determined by the FERC to be workably competitive, may be market based.
The FPA also grants the FERC jurisdiction over the sale or transfer of specified assets, including wholesale power sales contracts and generation facilities, and in some cases, jurisdiction over the issuance of securities or the assumption of specified liabilities and some interlocking directorates. Dispositions of EME's jurisdictional assets or certain types of financing arrangements may require FERC approval.
Deregulation of the electric generating sector began with the enactment of PURPA, which established a regulatory scheme for certain qualifying facilities. Most qualifying facilities, as that term is defined in PURPA, are exempt from the ratemaking and several other provisions of the FPA. It was further expanded with the passage of the Energy Policy Act of 1992, which established a regulatory scheme for EWGs and foreign utility companies. EWGs are subject to the FPA and to the FERC's ratemaking jurisdiction thereunder, but the FERC typically grants EWGs the authority to sell power at market-based rates to purchasers which are not affiliated electric utility companies as long as the absence of market power is shown. More recently, in EPAct 2005, the U.S. Congress recognized that a significant market for electric power generated by independent power producers, such as EME, has developed in the United States and indicated that competitive wholesale electricity markets have become accepted as a fundamental aspect of the electricity industry.
Each of EME's U.S. generating facilities has either been determined by the FERC to qualify as a qualifying facility, or the subsidiary owning the facility has been determined to be an EWG. In addition, EME's power marketing subsidiaries, including EMMT, have been authorized by the FERC to make wholesale market sales of power at market-based rates and are subject to the FERC ratemaking regulation under the FPA.
PURPA provides two primary benefits to qualifying facilities. First, all cogeneration facilities that are qualifying facilities are exempt from certain provisions of the FPA and regulations of the FERC thereunder. Second, the FERC regulations promulgated under PURPA initially required electric utilities to purchase electricity generated by qualifying facilities at a price based on the purchasing utility's avoided cost and to sell back up power to the qualifying
facility on a nondiscriminatory basis. EPAct 2005 provides for the elimination of a utility's obligation to purchase power from qualifying facilities at its avoided cost if the FERC determines that the relevant market meets certain conditions for competitive, nondiscriminatory access. The FERC's regulations also permit qualifying facilities and utilities to negotiate agreements for utility purchases of power at prices different from the utility's avoided costs, but do not require utilities to purchase power at such prices.
Several of EME's projects, including the Big 4 projects, are qualifying cogeneration facilities. Qualifying cogeneration facilities must produce electricity and useful thermal energy for an industrial or commercial process or heating or cooling applications in certain proportions to the facility's total energy output, and must meet certain efficiency standards. If one of the projects in which EME has an interest were to lose its qualifying facility status, the project would no longer be entitled to the qualifying facility-related exemptions from regulation and could become subject to rate regulation by the FERC under the FPA and additional state regulation. Loss of qualifying facility status could also trigger defaults under covenants to maintain qualifying facility status in the project's power sales agreements, steam sales agreements and financing agreements and result in refund claims from utility customers, termination, penalties or acceleration of indebtedness under such agreements. EME endeavors to monitor regulatory compliance by its qualifying facility projects in a manner that minimizes the risks of losing these projects' qualifying facility status.
Generally, projects that sell power to wholesale purchasers other than the local utility to which the project is interconnected require the transmission of electricity over power lines owned by others. The prices and other terms and conditions of transmission contracts are regulated by the FERC when the entity providing the transmission service is subject to FERC jurisdiction pursuant to the FPA.
The Energy Policy Act of 1992 laid the groundwork for a competitive wholesale market for electricity by, among other things, expanding the FERC's authority to order electric utilities to transmit third-party electricity over their transmission lines, thus allowing qualifying facilities, power marketers and EWGs to more effectively compete in the wholesale market.
The Illinois Power Agency Act regulates the procurement of power by Commonwealth Edison and the Ameren Illinois utilities for their bundled-rate customers. In June 2009, the newly created Illinois Power Agency became responsible for the administration, planning and procurement of power for Commonwealth Edison and the Ameren Illinois utilities' bundled-rate customers using a portfolio-managed approach that is to include competitively procured standard wholesale products and renewable energy resources.
The Illinois Commerce Commission, which continues in its role of oversight and approval of the power planning and procurement for utilities' bundled retail customers, approved in January 2009, a procurement plan for 2009 that was proposed by the Illinois Power Agency. The plan, which was based on five-year demand forecasts, uses a laddered procurement strategy for the 2009-2014 period. In 2009, the Illinois Power Agency acquired through a
single request for proposals roughly one third of the forecasted demand for bundled load for Commonwealth Edison and the Ameren Illinois utilities. Renewable requirements, in the first year, were purchased by way of one-year renewable energy credits; longer contracts may be included in future procurements if required by law or if approved by the Illinois Commerce Commission. In December 2009, the Illinois Power Agency's procurement plan for supply for the utilities' bundled customers for the 2010-2015 period was approved by the Illinois Commerce Commission.
The United States electric industry, including companies engaged in providing generation, transmission, distribution and retail sales and service of electric power, has undergone significant deregulation over the last three decades, which has led to increased competition, especially in the generation sector. See further discussion of regulations under "Regulation of EMEUnited States Federal Energy Regulation."
In areas where ISOs and RTOs have been formed, market participants have open access to transmission service typically at a system-wide rate. ISOs and RTOs may also operate real-time and day-ahead energy and ancillary service markets, which are governed by FERC-approved tariffs and market rules. The development of such organized markets into which independent power producers are able to sell has reduced their dependence on bilateral contracts with electric utilities.
In various regional wholesale power markets, market administrators and independent market monitors have acknowledged that generators historically have not been provided adequate compensation in the energy markets to avoid the retirement of existing generation or provide adequate financial incentives to attract new investment when needed to ensure system reliability. As a result, capacity markets have emerged to provide additional financial incentives for electric capacity by compensating supply resources for the capability to supply electricity when needed, and demand resources, for electricity they avoid using. Capacity markets are expected to provide additional revenues for independent power producers.
EME's largest power plants are its fossil fuel power plants located in Illinois, which are collectively referred to as the Midwest Generation plants, and the Homer City electric generating station located in Pennsylvania, which is referred to as the Homer City facilities. Collectively, both the Midwest Generation plants and Homer City facilities are referred to as the fossil-fueled facilities in this annual report. The fossil-fueled facilities are "merchant" generating stations that sell power primarily into PJM, an RTO which includes all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
PJM operates a wholesale spot energy market and determines the market-clearing price for each hour based on bids submitted by participating generators indicating the minimum prices at which a bidder is willing to dispatch energy at various incremental generation levels. PJM conducts both day-ahead and real-time energy markets. PJM's energy markets are based on locational marginal pricing, which establishes hourly prices at specific locations throughout
PJM by considering a number of factors, including generator bids, load requirements, transmission congestion and transmission losses. It can also be affected by, among other things, price caps and other market rules intended to facilitate competition and discourage the exercise of market power.
PJM requires all load-serving entities to maintain prescribed levels of capacity, including a reserve margin, to ensure system reliability. PJM also determines the amount of capacity available from each generator and operates capacity markets. PJM's capacity markets have a single market-clearing price. In June 2007, PJM implemented the reliability pricing model ("RPM") for capacity, under which capacity commitments are made in advance to provide a long-term pricing signal for capacity resources. The RPM is intended to provide a mechanism for PJM to meet the region's need for generation capacity, while allocating the cost to load-serving entities through a locational reliability charge. PJM also implemented marginal losses for transmission for its competitive wholesale electric market.
Load-serving entities and generators, such as EME's subsidiaries, Midwest Generation (with respect to the Midwest Generation plants) and Homer City (with respect to the Homer City facilities), may participate in PJM's capacity markets or transact capacity sales on a bilateral basis. Sales may also be made from PJM into the Midwest ISO ("MISO") RTO, which includes all or parts of Illinois, Wisconsin, Indiana, Michigan, Ohio, and other states in the region, and into the New York ISO ("NYISO"), which controls the transmission grid and energy and capacity markets for New York State.
Two of EME's wind projects sell electricity into RTOs as merchant generators. The Lookout wind project sells power into the PJM market, and the Goat Wind wind project sells power into the Electric Reliability Council of Texas market. The rest of EME's wind power generation facilities currently sell capacity, energy and/or ancillary services pursuant to bilateral contracts with electric utilities, regional cooperatives and public power authorities.
EME is subject to intense competition from energy marketers, investor-owned utilities, government-owned power agencies, industrial companies, financial institutions, and other independent power producers. Some of EME's competitors have a lower cost of capital than most independent power producers and, in the case of utilities, are often able to recover fixed costs through rate base mechanisms, allowing them to build, buy and upgrade generation without relying exclusively on market clearing prices to recover their investments. These companies may also have competitive advantages as a result of their scale, the location of their generation facilities, and their contractual arrangements with affiliated entities.
Environmental regulations, particularly those that impose stringent state specific emission limits, could put EME's coal-fired plants at a disadvantage compared with competing power plants operating in nearby states and subject only to federal emission limits. Potential future climate change regulations could also put EME's coal-fired plants at a disadvantage compared to both power plants utilizing other fuels and utilities that may be able to recover climate change compliance costs through rate mechanisms. In addition, the ability of EME's fossil fuel-fired plants to compete may be affected by governmental and regulatory activities
designed to support the construction and operation of power generation facilities fueled by renewable energy sources.
EME's power marketing and trading subsidiary, EMMT, markets the energy and capacity of EME's merchant generating fleet and, in addition, trades electric power and related commodity and financial products, including forwards, futures, options and swaps. EMMT segregates its marketing and trading activities into two categories:
As of December 31, 2009, EME's operations consisted of ownership or leasehold interests in the following operating projects:
As of December 31, 2009, EME had the projects described below under construction.
EME owns 100% of Big Sky Wind, LLC, which owns a 240 MW wind project under construction in Illinois, which EME refers to as the Big Sky wind project. Construction of this project commenced during the fourth quarter of 2009 and is scheduled for completion in late 2010. The project plans to sell electricity into the PJM market as a merchant generator or to third-party customers under power sales contracts.
EME owns 100% of Cedro Hill Wind, LLC, which owns a 150 MW wind project under construction in Texas, which EME refers to as the Cedro Hill wind project. Construction of this project commenced during the fourth quarter of 2009 and is scheduled for completion in early 2011. The project has entered into a 20-year power purchase agreement with the City of San Antonio.
EME had a development pipeline of potential wind projects with projected installed capacity of approximately 4,000 MW at January 31, 2010. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. As of December 31, 2009, EME had commitments to purchase 183 wind turbines (349 MW) and had 67 wind turbines (163 MW) in storage to be used for future wind projects. Successful completion of development of a wind project depends upon obtaining permits and agreements necessary to support an investment and may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase
renewable power at sufficient prices to earn an appropriate rate of return, and availability and prices of equipment.
During 2008, EME had entered into an agreement with First Solar Electric, LLC to provide design, engineering, procurement, and construction services for solar projects for identified customers, subject to the satisfaction of certain contingencies and entering into definitive agreements for such services for each project. During 2009, EME sold a number of solar projects under development to First Solar Electric and terminated the agreement.
In the past three fiscal years, the fossil-fueled facilities sold electric power generally into the PJM market by participating in PJM's capacity and energy markets or by transact in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 48%, 50% and 51% of EME's consolidated operating revenues for the years ended December 31, 2009, 2008 and 2007, respectively. For the years ended December 31, 2009 and 2008, a second customer, Constellation Energy Commodities Group, Inc. accounted for 16% and 10%, respectively, of EME's consolidated operating revenues. Sales to Constellation are primarily generated from the fossil-fueled facilities and consist of energy sales under forward contracts. In 2008 and 2007, EME also derived a significant source of its revenues from the sale of energy, capacity and ancillary services generated at the Midwest Generation plants to Commonwealth Edison under load requirements services contracts. By May 2009, all these contracts had expired. Sales under these contracts accounted for 12% and 19% of EME's consolidated operating revenues for the years ended December 31, 2008 and 2007, respectively.
EME maintains insurance policies consistent with those normally carried by companies engaged in similar business and owning similar properties. EME's insurance program includes all-risk property insurance, including business interruption, covering real and personal property, including losses from boiler or machinery breakdowns, and the perils of earthquake and flood, subject to specific sublimits. EME also carries general liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations, automobile liability insurance and excess liability insurance. Limits and deductibles in respect of these insurance policies are comparable to those carried by other electric generating facilities of similar size. No assurance can be given that EME's insurance will be adequate to cover all losses.
For a discussion of the seasonality of EME's Adjusted Operating income from its fossil-fueled facilities and unconsolidated affiliates, see "EMG: Results of OperationsAdjusted Operating Income from Consolidated Operations" and "Adjusted Operating Income from Unconsolidated Affiliates" in the MD&A.
Edison Capital's energy and infrastructure investments are in the form of leveraged leases, partnership interests in international infrastructure funds and affordable housing projects in the United States.
As of December 31, 2009, Edison Capital is the lessor with an investment balance (including current lease receivable) of $184 million in the following leveraged leases:
Edison Capital's investments may be affected by the financial condition of other parties, the performance of assets, regulatory, economic conditions and other business and legal factors.
Because Edison International does not own or operate any assets, other than the stock of its subsidiaries, it does not have any direct environmental obligations or liabilities. However, legislative and regulatory activities by federal, state, and local authorities in the United States relating to energy and the environment impose numerous restrictions on the operation of existing facilities and affect the timing, cost, location, design, construction, and operation of new facilities by Edison International's subsidiaries, as well as the cost of mitigating the environmental impacts of past operations. Many of these laws, regulations and other activities affect both SCE and EME's subsidiaries, although not always to the same extent. The environmental regulations and other developments discussed below have the largest impact on fossil-fuel fired power plants, and therefore the discussion in this section focuses on regulations applicable to the states of California, New Mexico, Illinois, and Pennsylvania, where such facilities are located.
Additional information about environmental matters affecting Edison International, including projected environmental capital expenditures, is included in the MD&A under the heading "Environmental Capital Requirements, Commitments and ContingenciesCompliance Costs" and in "Item 8. Edison International Notes to Consolidated Financial StatementsNote 6. Commitments and ContingenciesEnvironmental Remediation."
There have been a number of efforts at both the federal and state legislative and regulatory levels to adopt or enact regulations to reduce greenhouse gas emissions. Any climate change regulation or other legal obligation that would require substantial reductions in emissions of greenhouse gases or that would impose additional costs or charges for the emission of greenhouse gases could significantly increase the cost of generating electricity from fossil fuels, especially coal, as well as the cost of purchased power, which could adversely affect Edison International's business.
In June 2009, the U.S. House of Representatives passed the American Clean Energy and Security Act. The bill, which was endorsed by Edison International, would establish a cap-and-trade system for greenhouse gas emissions commencing in 2012. Under the cap-and-trade system, a cap to reduce aggregate greenhouse gas emissions from all covered entities would be established and decline over time. Emitters of greenhouse gases would be required to have allowances for greenhouse gas emissions during a relevant measurement period. The bill would provide for stated portions of required allowances to be allocated free of charge in declining amounts over time. Emitters of greenhouse gases would have to purchase the remainder of their required allowances in the open market, although a portion may be provided by so-called offset credits (for alternative greenhouse gas reduction efforts). Similar legislation was introduced in the U.S. Senate in September 2009. Edison International cannot predict whether legislation imposing limits on greenhouse gas emissions in the U.S. will be passed in 2010, and the timing, content and potential effects on Edison International of any legislation that may be enacted remain uncertain.
Even if Congress does not pass legislation mandating greenhouse gas emissions reductions, regulatory developments under the Clean Air Act ("CAA") may also result in greenhouse gas emissions requirements that could affect Edison International's subsidiaries. In April 2007, the U.S. Supreme Court held, in Massachusetts, et al. v. Environmental Protection Agency, that greenhouse gases are "air pollutants" under the CAA and that that the US EPA has a duty to determine whether greenhouse gas emissions from new motor vehicles contribute to climate change or offer a reasoned explanation for its failure to make such a determination. In response to this decision, in December 2009, the US EPA issued a finding that certain greenhouse gases, including carbon dioxide, endanger the public health and welfare, which enables the US EPA to establish greenhouse gas emissions limits for new light-duty vehicles. It is expected that the US EPA will issue the final light-duty vehicle emissions limits in March 2010.
The December 2009 endangerment finding will trigger future regulation of stationary sources of greenhouse gases, such as power plants, which the US EPA plans to phase in beginning in 2011. In addition, when the regulation of greenhouse gases from light-duty vehicles is finalized, greenhouse gas emissions will become subject to review under the CAA's Prevention of Significant Deterioration ("PSD") (construction or modification of major sources) permit program. Sources subject to a PSD review for greenhouse gases would be required to use best available control technology ("BACT") to control greenhouse gas emissions. Because carbon
dioxide is emitted in greater quantities than other CAA-regulated pollutants, regulating it under the PSD program would cover a large number of sources. To avoid the regulatory and enforcement consequences of such an outcome, in November 2009 the US EPA proposed a regulation, known as the "greenhouse gas tailoring rule." The greenhouse gas tailoring rule would redefine the PSD program to increase the threshold emission limit of carbon dioxide equivalents in a year from 250 tons to 25,000 metric tons. Whether or not this regulation is finalized, it is likely that EME's and SCE's fossil-fueled generating facilities would be major sources for purposes of the PSD programs. However, because the current PSD proposal affects only new or modified sources, it is not expected to have an immediate effect on EME's or SCE's existing generating plants. If EME or SCE are required to install pollution controls in the future or otherwise modify their operations in order to reduce carbon dioxide emissions, the impact will depend on the nature and timing of the controls to be applied, both of which remain uncertain. Edison International does not believe that currently there are commercially and technically feasible, full scale methods to control greenhouse gas emissions from its subsidiaries' existing fossil-fueled generating facilities.
California has enacted two laws regarding greenhouse gas emissions. The first law, the California Global Warming Solutions Act of 2006 (also referred to as AB 32), establishes a comprehensive program to reduce greenhouse gas emissions. AB 32 requires the California Air Resources Board ("CARB") to develop regulations, potentially including market-based compliance mechanisms, targeted to reduce California's greenhouse gas emissions to 1990 levels by 2020. The CARB's mandatory program will commence in 2012 and will implement incremental reductions aimed at reducing greenhouse gas emissions to 1990 levels by 2020. The CARB has released preliminary draft regulations establishing a California cap-and-trade program, which include revisions to the CARB's mandatory greenhouse gas emissions reporting regulation and are expected to be finalized by the CARB in October 2010.
The second law, SB 1368, required the CPUC and the California Energy Commission ("CEC") to adopt greenhouse gas emission performance standards that restrict the ability of investor owned and publicly owned utilities, respectively, to enter into long-term arrangements for the purchase of electricity. The standards must equal the performance of a combined-cycle gas turbine generator. The standards that have been adopted prohibit California load-serving entities, including SCE, from entering into long-term financial commitments with generators that emit more than 1,100 pounds of CO2 per MWh, which includes most coal-fired plants. Utility purchases of power generated by EME's facilities in California are subject to the emissions performance standards established in SB 1368. At this time, EME believes that all of its facilities in California meet the greenhouse gas emissions performance standard adopted under SB 1368, but EME will continue to monitor the regulations, as they are developed, for potential impact on its existing facilities and its projects under development.
SB 1368 also affects the ability of utilities to make long-term capital investments in generators that do not meet the emission performance standards. SB 1368 may prohibit SCE from making emission control expenditures at Four Corners.
California law also requires SCE to increase its procurement of electricity generated from renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from such resources by no later than December 31, 2010 or such later date as flexible compliance requirements permit. In addition, in September 2009, Governor Schwarzenegger issued an executive order directing the CARB to adopt a regulation consistent with 33% of retail sellers' annual electricity sales being obtained from renewable energy sources by 2020. The executive order provides that the regulation may accelerate or expand the timeframe for compliance as well as increase the targeted percentage of annual electricity sales to be obtained from renewable resources, based on a thorough assessment of relevant factors.
There are a number of regional initiatives relating to greenhouse gas emissions. Implementing regulations for such regional initiatives are likely to vary from state to state and may be more stringent and costly than federal legislative proposals currently being debated in Congress. It cannot yet be determined whether or to what extent any federal legislation would preempt regional or state initiatives, because these initiatives are in varying stages of development and implementation. If state and/or regional initiatives remain in effect after federal legislation is enacted, generators could be required to satisfy them in addition to federal standards.
Seven northeastern states have entered into a Memorandum of Understanding to establish a regional cap-and-trade greenhouse gas program for electric generators, referred to as the Regional Greenhouse Gas Initiative ("RGGI"). The RGGI states (now numbering 10) have passed laws and/or regulations to implement the RGGI program. Illinois and Pennsylvania are not signatories to the RGGI, although Pennsylvania participated in the process as an observer.
Illinois is a party to the Midwestern Greenhouse Gas Reduction Accord, by which six Midwestern states and the Canadian province of Manitoba agreed to develop regional greenhouse gas emission reduction goals within one year using a multi-sector cap-and-trade program to be implemented within 30 months. In June 2009, the Midwestern Greenhouse Gas Reduction Accord Advisory Group released its recommendations for emissions reduction targets and the design of a regional cap-and-trade program. The group is also drafting a framework for the cap-and-trade program that will serve as a basis for individual state legislative or regulatory action to implement the program.
Arizona, California, Montana, New Mexico, Oregon, Utah, Washington, and the Canadian provinces of British Columbia, Manitoba, Ontario and Quebec have launched the Western Climate Initiative to develop strategies to reduce greenhouse gas emissions in the region to 15% below 2005 levels by 2020. In September 2008, the Initiative partners released recommendations for a regional cap-and-trade program to help achieve that reduction goal. In February 2010, Arizona gave notice that it would not take part in the Western Climate Initiative's cap-and-trade program.
In 2009, three courts issued decisions in cases involving the question of whether power plants and other large sources could constitute public nuisances, making the sources potentially liable for damages or other remedies.
In October 2009, a California federal district court dismissed the complaint that had been filed by the native Alaskan village of Kivalina and the Kivalina Tribe in February 2008 against 24 defendants, including Edison International, who directly or indirectly engaged in the electric generating, oil and gas, or coal mining lines of business. Plaintiffs had alleged greenhouse gas emissions from the defendants' business activities contributed to global warming impacts that are melting the Arctic sea ice that protects the village from winter storms and that the village would soon need to be abandoned or relocated at a cost of between $95 million and $400 million. The court dismissed the plaintiffs' federal nuisance claims stating that they were inappropriate for judicial resolution because they required policy choices that were reserved to the legislative or executive branches of the government (the "political question doctrine"). The court also held that the plaintiffs did not have standing under federal law to bring the case, in part because of the lack of connection between the defendants' conduct and the harm that plaintiffs alleged was occurring. The court also dismissed plaintiffs' state law nuisance claims, but without prejudice to those claims being re-filed in state court. The plaintiffs have appealed the dismissal order to the Ninth Circuit Court of Appeals.
In contrast to the district court decision in Kivalina, the U.S. Court of Appeals for the Second Circuit, in September 2009, and the U.S. Court of Appeals for the Fifth Circuit, in October 2009, reversed and remanded lower court decisions that had dismissed complaints (filed in New York and Mississippi, respectively), against electric utilities and others, for injunctive relief and/or damages allegedly arising as a result of greenhouse gas emissions. These courts held that plaintiffs had standing and that their claims (sounding in various common law theories, including public nuisance in the New York case and public nuisance, private nuisance, trespass and negligence in the Mississippi case) were not barred by the political question doctrine. Neither Edison International nor its subsidiaries was named as a defendant in the New York case. At the time the action was dismissed by the court in Mississippi, the plaintiffs were seeking to amend their complaint to include Edison International and several affiliates of Edison International, including EME and SCE, as defendants.
Each of these differing rulings remains subject to appeal, rehearing, or potential review by the U.S. Supreme Court, and thus the ultimate impact of these cases remains uncertain. In addition, Edison International cannot predict whether the appellate decisions will result in the filing of new actions with similar claims or whether Congress, in considering climate legislation, will address directly the availability of courts for these sorts of claims.
SCE's independently certified greenhouse gas emission data for 2007, as reported to the California Climate Action Registry, showed that SCE emitted approximately 6.8 million metric tons from SCE-owned generation. SCE's reported emissions are pro-rated to its ownership interests in the emitting facilities. EME's 2007 greenhouse gas emissions were approximately 47.4 million metric tons, although they were not independently verified. Beginning with 2008 data, SCE will be reporting to TCR (as described below) and to the CARB. Edison International and its subsidiaries will begin reporting 2010 data to the US EPA in 2011. SCE reported 2008 greenhouse gas emission data to the CARB in June 2009. The CARB reporting is done in three parts: greenhouse gas emissions from SCE-owned generation, sulfur hexafluoride (SF6) emissions from SCE-owned or -operated equipment, and transaction reporting of MWhs purchased and resource types (from which the CARB calculates total greenhouse gas emissions). The CARB has not yet published its calculations on SCE's 2008 data.
Edison International became a founding reporter to The Climate Registry ("TCR"), formed in May 2008. TCR is a multi-national organization, which allows organizations to voluntarily inventory, verify, and publicly report their greenhouse gas emissions. Edison International filed initial emissions data for 2008 in September 2009 with TCR. This information did not cover all of Edison International's owned generation, as allowed under the TCR transitional reporter rules that apply for the first two years that an entity reports its emissions with TCR. Verified emissions data for Edison International is expected to be released publicly by TCR at the end of the second quarter of 2010.
In September 2009, the US EPA issued its Final Mandatory Greenhouse Gas Reporting Rule, which requires all energy sources within specified categories, including electric generation facilities, to begin monitoring greenhouse gas emissions in January 2010, and to submit annual reports to the US EPA by March 31 of each year, with the first report due on March 31, 2011.
Irrespective of the outcome of current federal or state legislative deliberations, Edison International believes that regulation of greenhouse gas emissions is likely to develop through increased costs, mandatory emission limits or other mechanisms, and that demand for energy from renewable sources will also continue to increase. As a result, SCE is creating a generation profile from wind, solar, geothermal, biomass and small hydro plants, that will be adaptable to a variety of regulatory and energy use environments. Its renewables portfolio of owned and procured sources currently consists of: 1,583 MW from wind, 956 MW from geothermal, 360 MW from solar, 178 MW from biomass, and 200 MW from small hydro. EME is developing several renewables projects and is the seventh largest wind power generator in the United States.
SCE has developed and promoted several energy efficiency and demand response initiatives in the residential market, including an ongoing meter replacement program to help reduce peak energy demand; a rebate program to encourage customers to invest in more efficient appliances; subsidies for purchases of energy efficient lighting products; appliance recycling
programs; widely publicized tips to customers for saving energy; and a voluntary demand response program which offers customers financial incentives to reduce their electricity use. SCE is also replacing its electro-mechanical grid control systems with computerized devices that allow more effective grid management.
The Boards of Directors of Edison International and SCE regularly receive reports from senior management regarding environmental issues that affect the companies, including climate change issues.
The CAA establishes a comprehensive program to protect and improve the nation's air quality by regulating certain air emissions from mobile and stationary sources. The states implement and administer many of these programs and may impose additional or more stringent requirements under the CAA scheme. The federal CAA, state clean air acts, and federal and state regulations implementing such statutes apply to plants owned by EME and SCE, as well as to plants from which SCE purchases power, but have their largest impact on the operation of coal-fired plants. The federal environmental regulations require states to adopt state implementation plans for certain pollutants, known as SIPs, which are equal to or more stringent than the federal requirements. These plans detail how the state will attain the standards that are mandated by the relevant law or regulation.
The CAA requires the US EPA to review the available scientific data for six criteria pollutants and establish a concentration level in the ambient air for those substances that is adequate to protect public health and welfare. These concentration levels are known as National Ambient Air Quality Standards, or NAAQS. The six criteria pollutants are carbon monoxide, lead, nitrogen dioxide, ozone, particulate matter, and sulfur dioxide.
Each state identifies the areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (non-attainment areas), and must develop a SIP both to bring non-attainment areas into compliance with the NAAQS and to maintain good air quality in attainment areas. All SIPs are submitted to the US EPA for approval. If a state fails to develop adequate plans, the US EPA will develop and implement a plan. The attainment status of areas can change, and states may be required to develop new SIPs that address these changes. Many of EME's facilities are located in counties that have not attained NAAQS for ozone and fine particulate matter. NOx emissions from power plants impact ambient air ozone levels and SO2 emissions from power plants impact ambient air fine particulate matter levels.
As described further below, on December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA to reduce mercury, NOx and SO2 emissions at the Midwest Generation plants. The agreement requires Midwest Generation to achieve air emission reductions for NOx and SO2, and those reductions should contribute to or effect compliance with various existing US EPA ambient air quality standards. It is possible that if lower ozone, particulate matter, NOx or SO2 NAAQS are finalized by US EPA in the future, Illinois may implement regulations that are more stringent than those required by Midwest Generation's existing agreement with Illinois EPA.
The CAIR, issued by the US EPA on March 10, 2005, was intended to address ozone and fine particulate matter attainment issues by reducing regional NOx and SO2 emissions. The CAIR had mandated significant reductions in NOx and SO2 emission allowance caps under the CAA in the 28 eastern states and the District of Columbia where compliance with the national ambient air quality standards for ozone and fine particulate matter was at issue. There is substantial uncertainty as to how the US EPA will address the deficiencies identified in 2008 decisions by the U.S. Court of Appeals for the D.C. Circuit that resulted in the remand of the CAIR to the US EPA for the issuance of a revised rule. The CAIR will remain in effect until the US EPA issues a revised rule, which is currently expected to be proposed in 2010. As a result of the D.C. Circuit Court's decisions, it is unclear whether the US EPA will be able to design a cap-and-trade program for NOx and SO2 that is consistent with the CAA. It is also unclear whether existing SIPs in certain states, particularly Illinois and Pennsylvania, will be sufficient to comply with the CAA. The fossil-fueled facilities may be subject to additional requirements, which could result in increased capital expenditures and operating expenses to comply with a revised CAIR or alternative regulations under the CAA. In the case of the Midwest Generation plants, these new requirements could exceed those applicable under the CPS.
In November 2009, the US EPA proposed a new one-hour NAAQS for SO2. The new standard is proposed to be between 50 and 100 parts per billion. The US EPA is required by a consent decree to take final action by June 2, 2010. The proposed rule would require states to submit SIPs in 2014, with compliance by 2017.
On December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA to reduce mercury, NOx and SO2 emissions at the Midwest Generation plants. The agreement has been embodied in an Illinois rule called the CPS. All of Midwest Generation's Illinois coal-fired electric generating units are subject to the CPS. The principal emission standards and control technology requirements for NOx and SO2 under the CPS are as described below:
NOx EmissionsBeginning in calendar year 2012 and continuing in each calendar year thereafter, Midwest Generation must comply with an annual and seasonal NOx emission rate of no more than 0.11 lbs/million Btu. In addition to these standards, Midwest Generation must install and operate SNCR equipment on Units 7 and 8 at the Crawford Station by December 31, 2015.
SO2 EmissionsMidwest Generation must comply with an overall SO2 annual emission rate beginning with 0.44 lbs/million Btu in 2013 and decreasing annually until it reaches 0.11 lbs/million Btu in 2019 and thereafter.
Midwest Generation has not decided upon a particular combination of retrofits to meet the required step down in emission rates and continues to review alternatives, including interim compliance solutions. The CPS also specifies that specific control technologies are to be installed on some units by specified dates. In these cases, Midwest Generation must either install the required technology by the specified deadline or shut down the unit. The CPS also requires Midwest Generation to shut down Units 1 and 2 at the Will County Station by December 31, 2010.
During 2009, Midwest Generation also conducted tests of NOx removal technology based on SNCR that may be employed to meet CPS requirements. Based on this testing, Midwest Generation has concluded that installation of SNCR technology on multiple units will meet the NOx portion of the CPS. Capital expenditures for installation of SNCR equipment are expected to be approximately $88 million in 2010 and approximately $70 million in 2011.
Testing of FGD technology based on dry sodium sorbent injection demonstrated significant reductions in SO2 when using the low-sulfur coal employed by Midwest Generation; however, further analysis and evaluation are required to determine the appropriate method to comply with the SO2 portion of the CPS. Use of FGD technology based on injection of dry sodium sorbent in combination with Midwest Generation's use of low-sulfur coal is expected to require substantially less capital and installation time than dry scrubber technology, but would likely result in higher ongoing operating costs than dry scrubber technology and may consequently result in lower dispatch rates and reduced competitiveness. Midwest Generation may also combine the use of dry sorbent injection technology with upgrades to its particulate removal systems to meet environmental regulations.
Midwest Generation cannot predict what specific method of SO2 removal will be used or the total costs that will be incurred to comply with the CPS. A decision whether or not to proceed with the above or other approaches to compliance remains subject to further analysis and evaluation of several factors, such as market conditions, regulatory and legislative developments, and forecasted capital and operating costs. Midwest Generation could elect to shut down units when required in order to comply with the SO2 removal requirements of the CPS. Due to existing uncertainties about the factors noted above, Midwest Generation may defer final decisions about particular units as long as possible. Accordingly, final decisions on whether to install controls, the particular controls that will be installed and the resulting capital commitments may not occur for up to two years for some of the units and potentially later for others. Midwest Generation continues to evaluate various scenarios and cannot predict the extent of shut downs and retrofits or the particular combination of retrofits and shut downs it may ultimately employ to comply with the CPS.
The Homer City facilities were subject to CAIR during 2009 and complied with both the NOx and SO2 requirements using existing equipment and purchasing of SO2 allowances. Pennsylvania adopted a state version of CAIR, which the US EPA approved in December 2009. Homer City expects to comply with the Pennsylvania CAIR, which is substantially similar to the federal CAIR, in the same manner in which it complies with the federal CAIR.
Until new federal standards are developed to replace the CAMR, EME will not be able to determine whether it will be necessary to undertake mercury emission control measures beyond those required by state regulations. The CAMR was established by the US EPA as an attempt to reduce mercury emissions from existing coal-fired power plants using a cap-and-trade program. EME's and SCE's coal-fired electric generating facilities (SCE currently has a 48% ownership interest in Units 4 and 5 at Four Corners) emit mercury and other regulated emissions. As a result of the decision by the U.S. Court of Appeals for the D.C. Circuit in February 2007 that rejected both the CAMR and the related decision by the US EPA to remove oil and coal-fired plants from the list of sources to be regulated under Section 112 of the CAA until CAMR is replaced by a new mercury rule, mercury regulation will come from state regulatory bodies. As described below, EME's coal-fired electric generating facilities are already subject to significant unit-specific mercury emission reduction requirements under Illinois and Pennsylvania law (although, as noted below, Pennsylvania's mercury regulations have been invalidated).
Midwest Generation's compliance with the CPS supersedes the Illinois mercury regulations that would otherwise be applicable to the Midwest Generation plants. The CPS requires that, beginning in calendar year 2015, and continuing thereafter on a rolling 12-month basis, Midwest Generation must either achieve an emission standard of .008 lbs mercury/GWh gross electrical output or a minimum 90% reduction in mercury for each unit (except Unit 3 at the Will County Station, which shall be included in calendar year 2016).
In addition to these standards, Midwest Generation was required to install and operate carbon injection equipment on all operating units. Installation of the equipment was completed in 2009. Capital expenditures relating to these controls were $42 million. Midwest Generation will also be required to install cold side electrostatic precipitator or baghouse equipment on Unit 7 at the Waukegan Station by December 31, 2013, and on Unit 3 at the Will County Station by December 31, 2015.
Until new legislation is passed authorizing the adoption of revised mercury regulations, the Homer facilities will not be required to comply with Pennsylvania mercury limitations. The Pennsylvania Department of Environmental Protection ("PADEP") attempted to implement regulations reducing the mercury emissions at coal-fired power plants by 80% by 2010 and 90% by 2015, as embodied in the Pennsylvania CAMR SIP. The Pennsylvania Supreme Court upheld a decision by the Commonwealth Court declaring Pennsylvania's mercury rule unlawful, invalid and unenforceable, and enjoining Pennsylvania from continued implementation and enforcement of the rule.
In September 2006, the US EPA issued a final rule that would significantly reduce the 24-hour fine particulate standard (from 65 ug/m3 to 35 ug/m3), but in February 2009, the U.S. Court of Appeals for the D.C. Circuit remanded the annual fine particulate matter standard to the US EPA for further review.
In March 2008, the US EPA issued a final rule revising the primary and secondary NAAQS for ozone, reducing the level of the 8-hour standard to 0.075 parts per million (ppm). In January 2010, the US EPA proposed revisions that would further lower the 8-hour primary ozone standard to a level in the range of 0.060 0.070 ppm and impose a cumulative, seasonal secondary standard in the range of 7 15 ppm-hours. Final standards are expected in August 2010. EME and SCE anticipate that any such further emission reduction obligations would not be imposed under this standard until 2014 at the earliest.
The Illinois SIP for 8-hour ozone was submitted to the US EPA on March 18, 2009. The SIP for fine particulates was to be submitted to the US EPA by April 5, 2008, but is currently expected to be submitted in 2010. As the fine particulate and ozone standards are finalized, as described above, Illinois may be required to implement additional emission control measures to address emissions of NOx, SO2 and volatile organic compounds.
In August 2007, the US EPA accepted PADEP's maintenance plan, which indicated that the existing (and upcoming) regulations controlling emissions of volatile organic compounds and NOx will result in continued compliance with the 8-hour ozone standard. However, in March 2009, the PADEP recommended to the US EPA that Indiana County (where the Homer City facilities are located) be designated non-attainment under the US EPA's 2008 revised 8-hour ozone standard. Until the US EPA completes its revision to the 8-hour ozone standard, redesignations are finalized, and additional regulations are developed to achieve attainment with the revised standard, EME will not know what specific requirements it will have to meet. However, EME expects that its currently installed SCRs will be capable of meeting these new requirements.
Effective April 1, 2009, the PADEP changed its air opacity policy, eliminating many exemptions and reducing the allowable exceedance rate to 0.5% of a unit's operating time. Homer City undertook optimization of unit ramp rates and combustion parameters at the Homer City facilities to reduce the deratings required to meet the opacity standards. Additional capital improvements may also be required. Homer City operated below the 0.5% exceedance rate during the second, third and fourth quarters of 2009.
With respect to fine particulates, in November 2009, the US EPA indicated that Indiana County, Homer City Township is not in compliance with applicable standards. The PADEP
must now submit an updated SIP by November 13, 2012. EME cannot determine the potential effects of the SIP at this time.
The regional haze rules under the CAA are designed to prevent impairment of visibility in certain federally designated areas. The goal of the rules is to restore visibility in mandatory federal Class I areas, such as national parks and wilderness areas, to natural background conditions by 2064. Sources such as power plants that are reasonably anticipated to contribute to visibility impairment in Class I areas may be required to install best available retrofit technology ("BART") or implement other control strategies to meet regional haze control requirements. The US EPA issued a final rulemaking on regional haze in 2005 requiring emission controls that constitute BART for industrial facilities that emit air pollutants which reduce visibility by causing or contributing to regional haze. These amendments required states to develop implementation plans to comply with BART by December 2007, to identify the facilities that will have to reduce SO2, NOx and particulate matter emissions, and then to set BART emissions limits for those facilities. Failure to do so results in a federal implementation plan.
Neither Illinois nor Pennsylvania has submitted a SIP that addresses regional haze issues under the CAA, and so, beginning on December 31, 2009 both states became subject to a two-year deadline after which a federal implementation plan will govern related emission issues. As a result of this uncertainty and the questions surrounding the CAIR program, EME cannot predict whether it will be required to install BART or implement other control strategies at the Midwest Generation plants and/or the Homer City facilities, what specific measures will be required or how much they will cost.
The CPS, discussed above in "Nitrogen Oxide and Sulfur DioxideIllinois," addresses emissions reductions at BART affected sources. In Pennsylvania, the PADEP considers the CAIR to meet the BART requirements, and the Homer City facilities are only required to consider reductions in emissions of suspended particulate matter (PM10), which at this time are being evaluated by the state.
In relation to Four Corners, the US EPA requested that the Arizona Public Service Company ("APS") perform a regional haze BART analysis. APS submitted the analysis to the US EPA, proposing the installation of certain combustion control equipment as BART for Four Corners. However, the US EPA issued an advanced notice of proposed rulemaking that called for post-combustion controls in the form of selective catalytic reduction ("SCR") pollution control equipment. A final US EPA determination on this matter is expected in late 2010. Until the final determination is issued, SCE cannot predict what pollution control equipment will be required at Four Corners and thus cannot accurately estimate the expenditures that would be necessary for such equipment. In any case, due to the investment constraints of SB 1368, the California law on greenhouse gas emission performance standards discussed above in "Climate ChangeState Legislative/Regulatory Developments," SCE does not expect to
be able to participate in any investment in SCR post-combustion controls or combustion controls at Four Corners. SCE thus does not expect to enter into any long-term ownership arrangements for its share of Four Corners Units 4 and 5 after the 2016 expiration of the current participant agreements due to the investment constraints of SB 1368.
The NSR regulations impose certain requirements on facilities, such as electric generating stations, if modifications are made to air emissions sources at the facility. Since 1999, the US EPA has pursued a coordinated compliance and enforcement strategy to address CAA compliance issues at the nation's coal-fired power plants. The strategy has included both the filing of suits against a number of power plant owners, and the issuance of administrative NOVs to a number of power plant owners alleging NSR violations.
On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that Midwest Generation and Commonwealth Edison violated various provisions of the NSR rules as well as state air regulations at the Midwest Generation plants. After attempts at settlement failed, on August 27, 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, based in part on the allegations in the NOV and alleging that construction projects undertaken prior to Midwest Generation's ownership violated various provisions of the NSR rules and Title V requirements. On June 12, 2008, Homer City received an NOV from the US EPA, which alleges that certain construction projects, all completed before Homer City acquired the Homer City facilities, violated various provisions of the NSR rules and Title V permit requirements. See "Item 3. Legal ProceedingsMidwest Generation New Source Review Lawsuit" and "Homer City New Source Review Notice of Violation" for further discussion.
In April 2009, APS, as operating agent of Four Corners, received a US EPA request pursuant to Section 114 of the CAA for information about Four Corners. The US EPA requested information about Four Corners and its operations, including information about Four Corners capital projects from 1990 to the present. APS has responded to the US EPA request. SCE understands that in other cases the US EPA has utilized similar Section 114 letters for examining whether power plants have triggered NSR requirements under the CAA and are therefore potentially subject to more stringent air pollution control requirements. No NSR enforcement-related proceedings have been initiated by the US EPA with respect to Four Corners. SCE cannot predict the outcome of this inquiry.
Regulations under the federal Clean Water Act require permits for the discharge of pollutants into United States waters and permits for the discharge of storm water from certain facilities.
The Clean Water Act also regulates the temperature of effluent discharges and the location, design, and construction of cooling water intake structures at generating facilities. California has a US EPA-approved program to issue individual or group (general) permits for the regulation of Clean Water Act discharges. California also regulates certain discharges not regulated by the US EPA.
In January 2007, the U.S. Court of Appeals for the Second Circuit rejected the US EPA rule on cooling water intake structures and remanded it to the US EPA. Among the key provisions remanded by the court were the use of cost-benefit analysis for determining the best technology available and the use of restoration to achieve compliance with the rule. On July 2007, the US EPA suspended the requirements for cooling water intake structures, pending further rulemaking. In April 2009, the U.S. Supreme Court reversed the Second Circuit and held that the US EPA may consider, but is not required to use, cost-benefit analysis in formulating regulations under Clean Water Act Section 316(b). The Court did not review the Second Circuit's rejection of the use of restoration as compliance with Section 316(b), which means the Second Circuit decision on this issue remains valid. The US EPA is currently rewriting the rule, and it is unknown whether revised regulations will use cost-benefit analysis.
EME has collected data at its potentially affected Midwest Generation plants in Illinois to begin determining what corrective actions might have been needed under the previous rule. Because there are no defined compliance targets absent a new rule, EME and SCE are reviewing a wide range of possible control technologies. Although the new rule could have a material impact on EME and SCE, until the final compliance criteria have been published, neither EME nor SCE can reasonably determine the financial impact.
In October 2007, the Illinois EPA filed a proposed rule with the Illinois Pollution Control Board ("PCB") that would establish more stringent thermal and effluent water quality standards for the Chicago Area Waterway System and Lower Des Plaines River. Midwest Generation's Fisk, Crawford and Will County Stations use water from the Chicago Area Waterway System and its Joliet Station uses water from the Lower Des Plaines River for cooling purposes. The rule, if implemented, is expected to affect the manner in which those stations use water for station cooling.
The proposed rule is the subject of an administrative proceeding before the Illinois PCB and must be approved by the Illinois PCB and the Illinois Joint Committee on Administrative Rules as well as the US EPA. Hearings began in January 2008, and are continuing in 2010. Midwest Generation is a party in those proceedings. It is not possible to predict the timing for resolution of the proceeding, the final form of the rule, or how it would impact the operation of the affected stations; however, significant capital expenditures may be required depending on the form of the final rule.
The discharge from the treatment plant receiving the wastewater stream from EME's Unit 3 wet scrubbing system at the Homer City facilities has exceeded the stringent water-quality based limits for selenium in the station's NPDES permit. Homer City and the PADEP entered
into a consent order and agreement related to selenium discharge, effective July 17, 2007, under which Homer City paid a civil penalty of $200,000 and agreed to install modifications to its wastewater system to achieve consistent compliance with discharge limits.
In June 2009 the California State Water Resources Control Board issued a draft "Statewide Water Quality Control Policy on the Use of Coastal and Estuarine Waters for Power Plant Cooling." The Policy would establish closed-cycle wet cooling as the best technology available for retrofitting existing "once-through" cooled plants, such as SCE's San Onofre, which use ocean water for cooling purposes. If the draft policy is adopted, it may significantly impact both operations at San Onofre and SCE's ability to procure timely generating capacity from fossil-fuel plants that use ocean water in once-through cooling systems. It may also impact system reliability and the cost of electricity to the extent other coastal power plants in California are forced to shut down or limit operations. The Policy has the potential to adversely affect California's nineteen once-through cooled power plants, which provide over 21,000 MW of combined, in-state generation capacity, including over 9,100 MW of capacity interconnected within SCE's service territory.
Under various federal, state and local environmental laws and regulations, a current or previous owner or operator of any facility may be required to investigate and remediate releases or threatened releases of hazardous or toxic substances or petroleum products located at that facility, and may be held liable for property damage, personal injury, natural resource damages, and investigation and remediation costs incurred by governmental entities and third parties in connection with these releases or threatened releases. Many of these laws, including the Comprehensive Environmental Response, Compensation, and Liability Act of 1980, ("CERCLA"), impose liability without regard to whether the owner knew of or caused the presence of the hazardous substances, and courts have interpreted liability under these laws to be strict and joint and several.
In connection with the ownership and operation of its facilities, Edison International may be liable for costs associated with hazardous waste compliance and remediation required by laws and regulations. Through an incentive mechanism, the CPUC allows SCE to recover in retail rates paid by its customers some of the environmental remediation costs at certain sites. Additional information about these laws and regulations appears in "Item 8. Edison International Notes to Consolidated Financial StatementsNote 6. Commitments and Contingencies."
US EPA regulations currently classify coal combustion wastes as solid wastes that are exempt from hazardous waste requirements. The exemption applies to fly ash, bottom ash, slag, and flue gas emission control wastes generated from the combustion of coal or other fossil fuels. The US EPA has studied coal combustion wastes extensively and in 2000 concluded that fossil fuel combustions wastes do not warrant regulation as a hazardous waste. The current classification of coal combustion wastes as exempt from hazardous waste requirements enables
beneficial uses of coal combustion wastes, such as for cement production and fill materials. Midwest Generation currently provides a portion of its coal combustion wastes for beneficial uses. Midwest Generation is also examining the impact of current and proposed emission control technologies on ash quality for beneficial use.
The US EPA is expected to publish proposed regulations relating to coal combustion waste in 2010. Additional regulation of the storage, disposal and beneficial reuse of coal combustion waste could affect the management of such wastes and could require EME and SCE to incur additional capital and operating costs, with no assurance that the additional costs could be recovered. Additionally, SCE may be prohibited from making such expenditures under SB 1368, the California law on greenhouse gas emission performance standards (see "Climate ChangeState Legislative/Regulatory Developments" above for a description of SB 1368).
Edison International's subsidiaries are subject to extensive environmental regulations that may involve significant and increasing costs and adversely affect them.
Edison International's subsidiaries are subject to extensive environmental regulation and permitting requirements that involve significant and increasing costs. SCE and EMG devote significant resources to environmental monitoring, pollution control equipment and emission allowances to comply with existing and anticipated environmental regulatory requirements. However, the current trend is toward more stringent standards, stricter regulation, and more expansive application of environmental regulations. The U.S. Congress is considering several proposals to regulate greenhouse gas emissions. The U.S. Environmental Protection Agency ("US EPA") has issued a finding that certain greenhouse gases endanger the public health and welfare and are air pollutants that are subject to the Clean Air Act. In addition, the attorneys general of several states, including California, certain environmental advocacy groups, and numerous state regulatory agencies in the United States have been focusing considerable attention on greenhouse gas emissions from coal-fired power plants and their potential role in climate change. The adoption of laws and regulations to implement greenhouse gas controls could adversely affect operations, particularly of the coal-fired plants. The continued operation of SCE and EMG facilities, particularly the coal-fired facilities, may require substantial capital expenditures for environmental controls. In addition, future environmental laws and regulations, and future enforcement proceedings by environmental authorities could affect the costs and the manner in which these subsidiaries conduct business. Current and future state laws and regulations in California also could increase the required amount of power that must be procured from renewable resources. Furthermore, changing environmental regulations could make some units uneconomical to maintain or operate. If the affected subsidiaries cannot comply with all applicable regulations, they could be required to retire or suspend operations at such facilities, or to restrict or modify the operations of these facilities, and their business, results of operations and financial condition could be adversely affected.
Edison International may be unable to meet its ongoing and future financial obligations and to pay dividends on its common stock if its subsidiaries are unable to pay upstream dividends or to repay funds for an extended period to Edison International.
Edison International is a holding company and, as such, it has no operations of its own. Edison International's ability to meet its financial obligations and to pay dividends on its common stock at the current rate is primarily dependent on the earnings and cash flows of its subsidiaries and their ability to make upstream distributions or to repay funds to Edison International. Prior to funding Edison International, Edison International's subsidiaries have financial and regulatory obligations that must be satisfied, including, among others, debt service and preferred stock dividends. Financial market and economic conditions may have an adverse effect on Edison International's subsidiaries. See "Risks Relating to SCE" and "Risks Relating to EMG" below for further discussion.
SCE's financial viability depends upon its ability to recover its costs in a timely manner from its customers through regulated rates.
SCE is a regulated entity subject to CPUC and FERC jurisdiction in almost all aspects of its business, including the rates, terms and conditions of its services, procurement of electricity for its customers, issuance of securities, dispositions of utility assets and facilities, aspects of project site identification and the operations of its electricity distribution systems. SCE's ongoing financial viability depends on its ability to recover from its customers in a timely manner its costs, including the costs of electricity purchased for its customers, through the rates it charges its customers as approved by the CPUC, and its ability to pass through to its customers in rates its FERC-authorized revenue requirements. SCE's financial viability also depends on its ability to recover through the rates it is allowed to charge an adequate return on capital, including long-term debt and equity. If SCE is unable to recover material amounts of its costs in rates in a timely manner or recover an adequate return on capital, its financial condition and results of operations could be materially adversely affected.
SCE's energy procurement activities are subject to regulatory and market risks that could adversely affect its financial condition and liquidity.
SCE obtains energy, capacity, renewable attributes and ancillary services needed to serve its customers from its own generating plants, as well as through contracts with energy producers and sellers. California law and CPUC decisions allow SCE to recover through the rates it is allowed to charge its customers reasonable procurement costs incurred in compliance with an approved procurement plan. Nonetheless, SCE's cash flows remain subject to volatility resulting from its procurement activities. In addition, SCE is subject to the risks of unfavorable or untimely CPUC decisions about the compliance of procurement activities with SCE's procurement plan and the reasonableness of certain procurement-related costs.
Many of SCE's power purchase contracts are tied to market prices for natural gas. Some of its contracts also are subject to volatility in market prices for electricity. SCE seeks to hedge
its market price exposure to the extent authorized by the CPUC. SCE may not be able to hedge its risk for commodities on favorable terms or fully recover the costs of hedges through the rates it is allowed to charge its customers, which could adversely affect SCE's liquidity and results of operation.
In its power purchase contracts and other procurement arrangements, SCE is exposed to risks from changes in the credit quality of its counterparties, many of whom may be adversely affected by the conditions in the financial markets. If a counterparty were to default on its obligations, SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power and this could have a material adverse effect on SCE's liquidity and financial condition if such costs cannot be recovered in a timely manner.
SCE is subject to extensive regulation and the risk of adverse regulatory decisions and changes in applicable regulations or legislation.
SCE operates in a highly regulated environment. SCE's business is subject to extensive federal, state and local energy, environmental and other laws and regulations. The CPUC regulates SCE's retail operations, and the FERC regulates SCE's wholesale operations. The Nuclear Regulatory Commission regulates SCE's nuclear power plants. The construction, planning, and project site identification of SCE's power plants and transmission lines in California are also subject to the jurisdiction of the California Energy Commission (for plants 50 MW or greater), and the CPUC. The construction, planning and project site identification of transmission lines that are outside of California are subject to the regulation of the relevant state agency.
SCE must periodically apply for licenses and permits from these various regulatory authorities and abide by their respective orders. Should SCE be unsuccessful in obtaining necessary licenses or permits or should these regulatory authorities initiate any investigations or enforcement actions or impose penalties or disallowances on SCE, SCE's business could be adversely affected. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to SCE or SCE's facilities in a manner that may have a detrimental effect on SCE's business or result in significant additional costs because of SCE's need to comply with those requirements.
SCE's financial condition and results of operations could be materially adversely affected if it is unable to successfully manage the risks inherent in operating and improving its facilities.
SCE owns and operates extensive electricity facilities that are interconnected to the United States western electricity grid. SCE is also undertaking large-scale new infrastructure construction, which involves risks related to permitting, governmental approvals, and construction delays. The operation of SCE's facilities and the facilities of third parties on which it relies involves numerous risks, including:
The occurrence of any of these events could result in lower revenues or increased expenses and liabilities, or both, which may not be fully recovered through insurance, rates or other means in a timely manner or at all.
There are inherent risks associated with operating nuclear power generating facilities.
Spent fuel storage capacity could be insufficient to permit long-term operation of SCE's nuclear plants.
SCE operates and is majority owner of San Onofre Nuclear Generating Station and is part owner of Palo Verde Nuclear Generating Station. The U.S. Department of Energy has defaulted on its obligation to begin accepting spent nuclear fuel from commercial nuclear industry participants by January 31, 1998. If SCE or the operator of Palo Verde were unable to arrange and maintain sufficient capacity for interim spent-fuel storage now or in the future, it could hinder the operation of the plants and impair the value of SCE's ownership interests until storage could be obtained, each of which may have a material adverse effect on SCE.
Existing insurance and ratemaking arrangements may not protect SCE fully against losses from a nuclear incident.
Federal law limits public liability claims from a nuclear incident to the amount of available financial protection which is currently approximately $12.6 billion. SCE and other owners of the San Onofre and Palo Verde Nuclear Generating Stations have purchased the maximum private primary insurance available of $375 million per site. If this public liability limit is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further revenue. If this were to occur, tension could exist between the federal government's attempt to impose revenue-raising measures upon SCE and the CPUC's willingness to allow SCE to pass this liability along to its customers, resulting in under-collection of SCE's costs. There can be no assurance of SCE's ability to recover uninsured costs in the event federal appropriations are insufficient.
SCE's insurance coverage may not be sufficient under all circumstances and SCE may not be able to obtain sufficient insurance.
SCE's insurance may not be sufficient or effective under all circumstances and against all hazards or liabilities to which it may be subject. A loss for which SCE is not fully insured could materially and adversely affect SCE's financial condition and results of operations. Further, due to rising insurance costs and changes in the insurance markets, insurance coverage may not continue to be available at all or at rates or on terms similar to those presently available to SCE.
SCE relies on access to the capital markets. If SCE were unable to access capital markets or the cost of capital was to substantially increase, its liquidity and operations could be adversely affected.
SCE's ability to fund operations and planned capital expenditure projects, as well as its ability to refinance debt and make scheduled payments of principal and interest depends on its cash flow and access to the capital markets. SCE's ability to arrange financing and the costs of such capital are dependent on numerous factors, including SCE's levels of indebtedness, maintenance of acceptable credit ratings, its financial performance, liquidity and cash flow, and other market conditions. Market conditions which could adversely affect SCE's financing costs and availability include:
SCE may not be successful in obtaining additional capital for these or other reasons. The failure to obtain additional capital from time to time may have a material adverse effect on SCE's liquidity and operations.
EME is subject to extensive environmental regulation and permitting requirements that may involve significant and increasing costs.
EME's operations are subject to extensive environmental regulations with respect to, among other things, air quality, water quality, waste disposal, and noise. EME is required to obtain, and comply with conditions established by, licenses, permits and other approvals in order to construct, operate or modify its facilities. Failure to comply with these requirements could subject EME to civil or criminal liability, the imposition of liens or fines, or actions by regulatory agencies seeking to curtail operations of EME's projects. See "Risks relating to Edison International."
The controls imposed on the Midwest Generation plants as a result of the Combined Pollutant Standard may require material expenditures or unit shutdowns.
Midwest Generation has entered into an agreement with the Illinois EPA to reduce mercury, NOx and SO2 emissions at the Midwest Generation plants. The agreement has been embodied in an Illinois rule called the Combined Pollutant Standard. All of Midwest Generation's Illinois coal-fired electric generating units are subject to the Combined Pollutant Standard. Capital expenditures relating to controls contemplated by the Combined Pollutant Standard could be significant and could make some units uneconomic to maintain or operate. Midwest Generation may ultimately decide to comply with Combined Pollutant Standard requirements by shutting down units rather than making improvements. Midwest Generation is evaluating technology and unit shutdown combinations and compliance solutions, to determine the economic effects of compliance with the Combined Pollutant Standard and optimal methods of compliance. For more information about the Combined Pollutant Standard requirements and Midwest Generation's plans for compliance, see "Item 1. BusinessEnvironmental Regulation of Edison International and SubsidiariesAir QualityNitrogen Oxide and Sulfur DioxideClean Air Interstate RuleIllinois" and "Edison International OverviewEnvironmental DevelopmentsMidwest Generation Environmental Compliance Plans and Costs" in the MD&A.
EME is subject to extensive energy industry regulation.
EME's operations are subject to extensive regulation by governmental agencies. EME's projects are subject to federal laws and regulations that govern, among other things, transactions by and with purchasers of power, including utility companies, the development and construction of generation facilities, the ownership and operations of generation facilities, and access to transmission. Under limited circumstances where exclusive federal jurisdiction is not applicable or specific exemptions or waivers from state or federal laws or regulations are otherwise unavailable, federal and/or state utility regulatory commissions may have broad jurisdiction over non-utility owned electric power plants.
The FERC may impose various forms of market mitigation measures, including price caps and operating restrictions, where it determines that potential market power might exist and that
the public interest requires mitigation. In addition, many of EME's facilities are subject to rules, restrictions and terms of participation imposed and administered by various Regional Transmission Operators and Independent System Operators. For example, Independent System Operators and Regional Transmission Operators may impose bidding and scheduling rules, both to curb the potential exercise of market power and to facilitate market functions. Such actions may materially affect EME's results of operations.
Generation facilities are also subject to federal, state and local laws and regulations that govern, among other things, the geographical location, zoning, land use and operation of a project. EME in the course of its business must obtain and periodically renew licenses, permits and approvals for its facilities. There is no assurance that the introduction of new laws or other future regulatory developments will not have a material adverse effect on EME's business, results of operations or financial condition, nor is there any assurance that EME will be able to obtain and comply with all necessary licenses, permits and approvals for its projects. If projects cannot comply with all applicable regulations, EME's business, results of operations and financial condition could be adversely affected.
EME has substantial interests in merchant energy power plants which are subject to market risks related to wholesale energy prices.
EME's merchant energy power plants do not have long-term power purchase agreements. Because the output of these power plants is not committed to be sold under long-term contracts, these projects are subject to market forces which determine the amount and price of energy, capacity and ancillary services sold from the power plants. The market price for energy, capacity and ancillary services is influenced by multiple factors beyond EME's control, which include:
In addition, unlike most other commodities, electric power can only be stored on a very limited basis and generally must be produced when it is to be used. As a result, the wholesale power markets are subject to significant and unpredictable price fluctuations over relatively short periods of time. Due to the volume of sales into PJM from the fossil-fueled facilities, EME has concentrated exposure to market conditions and fluctuations in PJM. There is no assurance that EME's merchant energy power plants will be successful in selling power into their markets or that the prices received for their power will generate positive cash flows. If EME's merchant energy power plants do not meet these objectives, they may not be able to generate enough cash to service their own debt and lease obligations, which could have a material adverse effect on EME.
EME's financial results can be affected by changes in fuel prices, fuel transportation cost increases, and interruptions in fuel supply.
EME's business is subject to changes in fuel costs, which may negatively affect its financial results and financial position by increasing the cost of producing power. Fuel costs can be influenced by many factors outside EME's control, including weather, market liquidity, transportation inefficiencies, demand for energy commodities (both as fuel and as feedstock for manufacturing processes), natural gas, crude oil and coal production levels, natural disasters, wars, embargoes and other catastrophic events, governmental regulation and legislation, and the creditworthiness, liquidity and willingness of fuel suppliers and transporters to do business with EME and its subsidiaries. The fuel markets can be volatile, and actual fuel prices can differ from EME's expectations.
Although EME attempts to purchase fuel based on its expected requirements, it is still subject to the risks of supply interruptions, transportation cost increases, and fuel price volatility. In addition, fuel deliveries will not exactly match energy sales, due in part to the need to purchase fuel inventories in advance for reliability and dispatch requirements. The price at which EME can sell its energy may not rise or fall at the same rate as a corresponding rise or fall in fuel costs. All of these factors may have an adverse effect on EME's financial condition and results of operations.
EME may not hedge market risks effectively.
EME is exposed to market risks through its ownership and operation of merchant energy power plants and through its power marketing business. These market risks include, among others, volatility arising from the timing differences associated with buying fuel, converting fuel into energy and delivering energy to a buyer. EME uses forward contracts and derivative
instruments, such as futures contracts and options, to manage market risks and exposure to fluctuating electricity and fuel prices. However, EME cannot provide assurance that these strategies will successfully mitigate market risks.
EME's hedging activities may not cover the entire exposure of its assets or positions to market price volatility, and the level of coverage will vary over time. Amounts hedged at any given time are not indicative of amounts that may be hedged in the future. Fluctuating commodity prices may affect EME's financial results, either favorably or unfavorably, to the extent that assets and positions have not been hedged. In addition, EME's risk management strategies may not be as effective as anticipated.
The effectiveness of EME's hedging activities may depend on the amount of credit available to post collateral, either in support of performance guarantees or as a cash margin. The amount of credit support that must be provided typically is based on the difference between the contract price of the commodity and its current market price. Significant movements in market prices can result in a requirement to provide cash collateral and letters of credit in very large amounts. Without adequate liquidity to meet margin and collateral requirements, EME could be exposed to the following:
As a result of these and other factors, EME cannot predict the effect that risk management decisions may have on its business, operating results or financial position.
Competition could adversely affect EME's business.
EME has numerous competitors in all aspects of its business some of whom may have greater liquidity, greater access to credit and other financial resources, lower cost structures, larger staffs or more experience than EME. EME's competitors may be able to respond more quickly and efficiently to new laws and regulations or emerging technologies, or to devote greater resources to the development, operation, and maintenance of their power generation facilities than EME. Multiple participants in the wholesale markets, including many regulated utilities, have a lower cost of capital than most merchant generators and often are able to recover fixed costs through rate base mechanisms, allowing them to build, buy and upgrade generation assets without relying exclusively on market clearing prices to recover their investments. These factors could affect EME's ability to compete effectively in the markets in which those entities operate.
Newer plants owned by EME's competitors are often more efficient than EME's facilities and may also have lower costs of operation. Over time, some of EME's merchant facilities may become obsolete in their markets, or be unable to compete with such plants.
In addition to the competition already existing in the markets in which EME presently operates or may consider operating in the future, EME is likely to encounter significant competition as a result of further consolidation of the power industry by mergers and asset reallocations, which could create larger competitors, as well as new market entrants.
EME may not be able to raise capital on favorable terms, which could adversely affect its results of operation.
Liquidity is essential to EME's business. EME cannot provide assurance that its projected sources of capital will be available when needed or that its actual cash requirements will not be greater than expected. Lack of available capital may affect EME's ability to complete environmental improvements at the fossil-fueled facilities, which could lead to the eventual shutdown of a material part of such facilities. Lack of available capital could also affect EME's ability to complete the development of sites for renewable projects deploying current turbine commitments, which could lead to postponement or cancellation of the turbine commitments subject to the provisions of the related contracts. EME cannot provide assurance that its projected sources of capital will be available when needed or that its actual cash requirements will not be greater than expected.
EME and its subsidiaries have a substantial amount of indebtedness, including long-term lease obligations.
As of December 31, 2009, EME's consolidated debt was approximately $4.0 billion. In addition, EME's subsidiaries had $3.2 billion of long-term, power plant lease obligations that are due over a period ranging up to 25 years. The substantial amount of consolidated debt and financial obligations presents the risk that EME and its subsidiaries might not have sufficient cash to service their indebtedness or long-term lease obligations and that the existing corporate debt, project debt and lease obligations could limit the ability of EME and its subsidiaries to grow their business, to compete effectively, to operate successfully under adverse economic conditions, to comply with evolving environmental regulations, or to plan for and react to business and industry changes. If cash flows and capital resources were insufficient to cover scheduled debt payments, EME or its subsidiaries might have to reduce or delay capital expenditures (including environmental improvements required by the CPS, which could in turn lead to unit shutdowns), sell assets, seek additional capital, or restructure or refinance the debt. The terms of EME's or its subsidiaries' debt may not allow these alternative measures, the debt or equity may not be available on acceptable terms, and these alternative measures may not satisfy all scheduled debt service obligations.
EME conducts a substantial portion of its operations through its subsidiaries and may be limited in its ability to access funds from these subsidiaries to service its debt.
EME depends to a large degree upon dividends and other intercompany transfers of funds from its subsidiaries to meet debt service and other obligations. In addition, the ability of EME's subsidiaries to pay dividends and make other payments to EME may be restricted by, among other things, applicable corporate and other laws, potentially adverse tax
consequences, and agreements entered into by the subsidiaries. If EME is unable to access the cash flow of its subsidiaries, it may have difficulty meeting its own debt obligations.
Restrictions in the instruments governing EME's indebtedness and the indebtedness and lease obligations of its subsidiaries limit EME's and its subsidiaries' ability to enter into specified transactions that they otherwise might enter into.
The instruments governing EME's indebtedness and the indebtedness and lease obligations of its subsidiaries contain financial and investment covenants. Restrictions contained in these documents or documents EME or its subsidiaries enter in the future could affect, and in some cases significantly limit or prohibit, EME's ability and the ability of its subsidiaries to, among other things, incur, refinance, and prepay debt, make capital expenditures, pay dividends and make other distributions, make investments, create liens, sell assets, enter into sale and leaseback transactions, issue equity interests, enter into transactions with affiliates, create restrictions on the ability to pay dividends or make other distributions and engage in mergers and consolidations. These restrictions may significantly impede EME's ability and the ability of its subsidiaries to take advantage of business opportunities as they arise, to grow its business or to compete effectively. In addition, these restrictions may significantly impede the ability of EME's subsidiaries to make distributions to EME.
In connection with the entry into new financings or amendments to existing financing arrangements, EME's financial and operational flexibility may be further reduced as a result of more restrictive covenants, requirements for security and other terms that are often imposed on sub-investment grade entities.
EME's development projects or future acquisitions may not be successful.
EME's development activities are subject to risks including, without limitation, risks related to the identification of project sites, financing, construction, permitting, governmental approvals and the negotiation of project agreements, including power purchase agreements. As a result of these risks, EME may not be successful in developing new projects, or the timing of such development may be delayed beyond the date that turbines are ready for installation. Projects under development may be adversely affected by delays in turbine deliveries or start-up problems related to turbine performance, and agreements with off-takers may contain damages and termination provisions related to failures to meet specified milestones. Moreover, recent economic conditions may affect the willingness of local utilities to enter into new power purchase agreements due to uncertainties over future load requirements, among other factors. If a project under development is abandoned, EME would expense all capitalized costs incurred in connection with that project, and could incur additional losses associated with any related contingent liabilities.
In support of its development activities, EME has entered into commitments to purchase wind turbines for future projects and may make substantial additional commitments in the future. If EME is not successful in developing new projects, it may be required to cancel turbine orders or sell turbines that were purchased. Such cancellations and/or sales may result in substantial losses and, under certain circumstances, may give rise to disputes with the turbine vendor. In
addition, EME cannot provide assurance that its development projects or acquired assets will generate sufficient cash flow to support the indebtedness incurred to acquire them or to fund the capital expenditures needed to develop them, or that EME will ultimately realize a satisfactory rate of return.
EME's projects may be affected by general operating risks and hazards customary in the power generation industry. EME may not have adequate insurance to cover all these hazards.
The operation of power generation facilities involves many operating risks, including:
These and other hazards can cause significant personal injury or loss of life, severe damage to and destruction of property, plant and equipment, contamination of or damage to the environment, and suspension of operations. The occurrence of one or more of the events listed above could decrease or eliminate revenues generated by EME's projects or significantly increase the costs of operating them, and could also result in EME being named as a defendant in lawsuits asserting claims for substantial damages, potentially including environmental cleanup costs, personal injury, property damage, fines and penalties.
Unplanned outages typically increase operation and maintenance expenditures and reduce revenues. EME could also be required to purchase replacement power in the open market to satisfy contractual commitments. Equipment and plant warranties, guarantees and insurance may not be sufficient or effective under all circumstances to cover lost revenues or increased expenses. A decrease or elimination in revenues generated by the facilities or an increase in the costs of operating them could decrease or eliminate funds available to meet EME's obligations as they become due and could have a material adverse effect on EME. A default
under a financing obligation of a project entity could cause EME to lose its interest in the project.
The creditworthiness of EME's customers, suppliers, transporters and other business partners could affect EME's business and operations.
EME is exposed to risks associated with the creditworthiness of its key customers, suppliers and business partners, many of whom may be adversely affected by the current conditions in the financial markets. Deterioration in the financial condition of EME's counterparties increases the possibility that EME may incur losses from the failure of counterparties to perform according to the terms of their contractual arrangements.
EME's operations depend on contracts for the supply and transportation of fuel and other services required for the operation of its generation facilities and are exposed to the risk that counterparties to contracts will not perform their obligations. If a fuel supplier or transporter failed to perform under a contract, EME would need to obtain alternate supplies or transportation, which could result in higher costs or disruptions in its operations. If the defaulting counterparty is in poor financial condition, damages related to a breach of contract may not be recoverable. Accordingly, the failure of counterparties to fulfill their contractual obligations could have a material adverse effect on EME's financial results.
As a holding company, Edison International does not directly own any significant properties other than the stock of its subsidiaries. The principal properties of SCE are described above under "Southern California Edison CompanyProperties of SCE." Properties of EME are discussed above under "Edison Mission Group Inc.Properties of EME".
During the period 2006-2008, the South Coast Air Quality Management District ("SCAQMD") issued five notices of violation ("NOVs") alleging violations of the NOx emission limits and related Regional Clean Air Incentives Market (RECLAIM) trading credit (to offset NOx emissions) requirements by certain of SCE's diesel generation units on Catalina Island. A settlement agreement, which resolves all of the NOVs, was fully executed in April 2009 and requires SCE to install new equipment by December 31, 2011 or pay a $3 million fine if the equipment is not installed by that date.
On June 12, 2008, Homer City received an NOV from the US EPA alleging that, beginning in 1988, Homer City (or former owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the Prevention of Significant Deterioration ("PSD") requirements of the Clean Air Act ("CAA"). The US EPA also alleges that Homer City has failed to file timely and complete Title V permits. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. On June 30, 2009 and January 2, 2010, the US EPA issued requests for information to Homer City under Section 114 of the CAA. Homer City is working on a response to the requests. Homer City has met with the US EPA and has expressed its intent to explore the possibility of a settlement. If no settlement is reached and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. EME cannot predict at this time what effect this matter may have on its facilities, its results of operations, financial position or cash flows.
Homer City has sought indemnification for liability and defense costs associated with the NOV from the sellers under the asset purchase agreement pursuant to which Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting the defense of the claims.
Homer City notified the sale-leaseback owner participants of the Homer City facilities of the NOV under the operative indemnity provisions of the sale-leaseback documents. The owner participants of the Homer City facilities, in turn, have sought indemnification and defense from Homer City for costs and liabilities associated with the Homer City NOV. Homer City responded by undertaking the indemnity obligation and defense of the claims.
On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the PSD requirements and of the New Source Performance Standards of the CAA, including alleged requirements to obtain a construction permit and to install BACT at the time of the projects. The US EPA also alleged that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleged violations of certain opacity and particulate matter standards at the Midwest Generation plants. At approximately the same time, Commonwealth Edison received an NOV substantially similar to the Midwest Generation NOV. Midwest Generation, Commonwealth Edison, the US EPA, and the U.S. Department of Justice ("DOJ"), along with several Chicago-based environmental action groups, had discussions designed to explore the possibility of a settlement but no settlement resulted.
On August 27, 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, alleging claims substantially similar to those in the NOV. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint calls for an injunction ordering Midwest Generation to install best available control technology ("BACT") at all units subject
to the complaint; to obtain new PSD or NSR permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. The remedies sought by the plaintiffs in the lawsuit could go well beyond those required under the CPS. By order dated January 19, 2010, the court allowed a group of Chicago-based environmental action groups to intervene in the case.
The owner participants of the Powerton and Joliet Stations have sought indemnification and defense from Midwest Generation and/or EME for costs and liabilities associated with these matters. EME responded by undertaking the indemnity obligation and defense of the claims. An adverse decision could involve penalties and remedial actions that would have a material adverse impact on the financial condition and results of operations EME.
EME cannot predict the outcome of these matters or estimate the impact on its facilities, its results of operations, financial position or cash flows.
Information about the Navajo Nation litigation appears in the "Item 8. Edison International Notes to Consolidated Financial StatementsNote 6. Commitments and Contingencies."
Pursuant to Form 10-K's General Instruction G(3), the following information is included as an additional item in Part I:
As set forth in Article IV of Edison International's and the relevant subsidiary's Bylaws, the elected officers of Edison International and its subsidiaries are chosen annually by, and serve at the pleasure of, Edison International and the relevant subsidiary's Board of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected. All of the officers of Edison International and its subsidiaries have been actively engaged in the business of Edison International and its subsidiaries for more than five years, except for Messrs. Adler and David, and have served in their present positions for the periods stated below. Additionally,
those officers who have had other or additional principal positions in the past five years had the following business experience during that period:
Edison International Common Stock is traded on the New York Stock Exchange under the symbol "EIX."
Market information responding to Item 5 is included in "Item 8. Edison International Notes to Consolidated Financial StatementsNote 19. Quarterly Financial Data." There are restrictions on the ability of Edison International's subsidiaries to transfer funds to Edison International that materially limit the ability of Edison International to pay cash dividends. Such restrictions are discussed in the MD&A under the heading "Edison International OverviewParent Company Liquidity and in "Item 8. Edison International Notes to Consolidated Financial StatementsNote 3. Liabilities and Lines of Credit." The number of common stock shareholders of record of Edison International was 47,620 on February 25, 2010. Additional information concerning the market for Edison International's Common Stock is set forth on the cover page hereof.
The following table contains information about all purchases made by or on behalf of Edison International or any affiliated purchaser (as defined in Rule 10b-18(a)(3) under the Exchange Act) of shares or other units of any class of Edison International's equity securities that is registered pursuant to Section 12 of the Exchange Act.
never registered in Edison International's' name and none of the shares pur chased were retired as a result of the transactions.
Note: Assumes $100 invested on December 31, 2004 in stock or index including reinvestment of dividends. Performance of the Philadelphia Utility Index is regularly reviewed by management and the Board of Directors in understanding Edison International's relative performance and is used in conjunction with elements of the company's incentive compensation program.
The selected financial data was derived from Edison International's audited financial statements and is qualified in its entirety by the more detailed information and financial statements, including notes to these financial statements, included in this annual report.
Edison International is a holding company whose principal operating subsidiaries are SCE, a rate-regulated electric utility, and EMG, the holding company of Edison International's competitive power generation (EME) and financial services (Edison Capital) segments. As a holding company, Edison International's progress and outlook are the result of developments at its operating subsidiaries.
This overview is presented in five sections:
Edison International's earnings are prepared in accordance with generally accepted accounting principles used in the United States. Management uses core earnings by principal operating subsidiary internally for financial planning and for analysis of performance. Core earnings by principal operating subsidiary are also used when communicating with analysts and investors regarding our earnings results to facilitate comparisons of the Company's performance from period to period. Core earnings is a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings are defined as earnings attributable to Edison International shareholders less income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: settlement of prior year tax liabilities; exit activities, including lease terminations, asset impairments, sale of certain assets, early debt extinguishment costs and other activities that are no longer continuing; and non-recurring regulatory or legal proceedings.
SCE's 2009 core earnings increased from 2008 primarily due to higher operating income associated with the CPUC and FERC 2009 general rate case decisions, partially offset by higher income taxes. In addition, core earnings were favorably impacted from lower than planned financings during the year, primarily from cash received for tax-related timing differences and other benefits.
During 2009, SCE received general rate case decisions from the CPUC and FERC, as follows:
EMG 2009 core earnings were significantly lower than 2008 primarily due to the following:
Consolidated changes in non-core items for Edison International include the following:
See "SCE: Results of Operations" for discussion of SCE results of operations, including a comparison of 2008 results to 2007. Also, see "EMG: Results of Operations" for discussion of EMG results of operations, including a comparison of 2008 results to 2007.
SCE's capital program is focused primarily in five areas:
SCE plans to utilize much of the cash currently generated from its operations and issuance of additional debt and preferred stock for its capital program. SCE's capital expenditures in 2009 totaled $2.9 billion. SCE projects that capital expenditures will be in the range of $3.3 billion to $4.0 billion in 2010 and that the 2010 - 2014 total capital investment plan will be in the range of $18 billion to $21.5 billion. The rate of actual capital spending will be affected by permitting, regulatory, market and other factors as discussed further under "SCE: Liquidity and Capital ResourcesCapital Investment Plan."
Midwest Generation is subject to various requirements with respect to environmental compliance for the Midwest Generation plants. In 2006, Midwest Generation entered into an agreement with the Illinois EPA, which has been embodied in an Illinois rule called the CPS, to control emission of mercury, NOx and SO2 from its coal-fired plants. During 2008 and 2009, Midwest Generation installed equipment to reduce its mercury emissions. During 2009, Midwest Generation also conducted tests of NOx removal technology based on SNCR and SO2 removal using flue gas desulfurization technology based on dry sodium sorbent injection that may be employed to meet CPS requirements. Based on this testing, Midwest Generation has concluded that installation of SNCR technology on multiple units will meet the NOx
portion of the CPS. Capital expenditures for installation of SNCR technology are expected to be approximately $88 million in 2010 and $70 million in 2011.
Testing of flue gas desulfurization technology based on injection of dry sodium sorbent demonstrated significant reductions in SO2 emissions when using low-sulfur coal employed by Midwest Generation; however, further analysis and evaluation are required to determine the appropriate method to comply with the SO2 portion of the CPS. Use of flue gas desulfurization technology based on injection of dry sodium sorbent in combination with Midwest Generation's use of low-sulfur coal is expected to require substantially less capital and installation time than dry scrubber technology, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of the plants. Midwest Generation may also combine the use of dry sorbent injection technology with upgrades to its particulate removal systems to meet environmental regulations.
Midwest Generation does not yet know what specific method of SO2 removal will be used or the total costs that will be incurred to comply with the CPS. Any and a decision regarding whether or not to proceed with the above or other approaches to compliance remains subject to further analysis and evaluation of several factors, including market conditions, regulatory and legislative developments and forecasted capital and operating costs. Due to existing uncertainties about these factors, Midwest Generation may defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, the particular controls that will be installed, and the resulting capital commitments may not occur for up to two years for some of the units and potentially further out for others. Midwest Generation could elect to shut down units when required in order to comply with the SO2 removal requirements of the CPS. Midwest Generation continues to evaluate various scenarios and cannot predict the extent of shutdowns and retrofits or the particular combination of retrofits and shutdowns it may ultimately employ to comply with CPS.
In August 2009, the US EPA and the State of Illinois filed a lawsuit against Midwest Generation in Illinois federal court based on claims contained in a 2007 NOV regarding alleged violations of the New Source Performance Standards of the CAA, the CAA's Title V operating permit requirements and applicable opacity and particulate matter standards. Midwest Generation is contesting such claims. The lawsuit seeks, among other things, substantial monetary penalties and an injunction requiring Midwest Generation to install controls sufficient to meet BACT emissions rates as determined by the court at all units subject to the lawsuit. See "Item 3. Legal ProceedingsMidwest Generation New Source Review Lawsuit" for further discussion. Should liability of Midwest Generation be established, remedies ordered by the court could go beyond what is required for compliance with the CPS.
Homer City operates SCR equipment on all three units to reduce NOx emissions, operates flue gas desulfurization equipment on Unit 3 to reduce SO2 emissions, and uses coal-cleaning equipment onsite to reduce the ash and sulfur content of raw coal to meet both combustion and environmental requirements. Homer City may be required to install additional
environmental equipment on Unit 1 and Unit 2 to comply with environmental regulations under the CAIR and Pennsylvania mercury regulations. If required, the timing of such compliance remains uncertain. Homer City projects that if flue gas desulfurization equipment becomes required, it would need to make capital commitments for such equipment three to four years in advance of the effectiveness of such requirements. Homer City continues to review technologies available to reduce SO2 and mercury emissions and to monitor developments related to mercury and other environmental regulations. Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction could affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. Homer City will have limited ability to obtain additional outside capital for such projects without amending its lease and related agreements. EME is under no contractual or other obligation to provide funding to Homer City.
The nature of future environmental regulation and legislation will have a substantial impact on Edison International. Edison International believes that resolution of current uncertainties about the future, through well-balanced and appropriately flexible regulation and legislation, is needed to support the necessary evolution of the electric industry into using cleaner, more efficient infrastructure and to attract the capital ultimately needed for this effort. Legislative, regulatory, and legal developments related to potential controls over greenhouse gas emissions in the United States are ongoing. Actions to limit or reduce greenhouse gas emissions could significantly increase the cost of generating electricity from fossil fuels as well as the cost of purchased power. In the case of utilities, like SCE, these costs are generally borne by customers, whereas the increased costs for competitive generators, like EME, must be recovered through market prices for electricity.
Recent significant developments include the following:
Last year, the California State Water Resources Board released a draft policy, which would establish closed-cycle wet cooling as required technology for retrofitting existing once-through cooled plants like San Onofre and many of the existing gas-fired power plants along the California coast. If the policy is adopted by the Board, it may result in significant capital expenditures at San Onofre and may affect its operations. It may also significantly impact SCE's ability to procure generating capacity from fossil-fuel plants that use ocean water in once-through cooling systems. It may also impact system reliability and the cost of electricity to the extent other coastal power plants in California are forced to shut down or limit operations. The policy has the potential to adversely affect California's nineteen once-through cooled power plants, which provide over 21,000 MW of combined, in-state generation capacity, including over 9,100 MW of capacity interconnected within SCE's service territory.
EME has a development pipeline of potential wind projects with projected installed capacity of approximately 4,000 MW at January 31, 2010 compared to approximately 5,000 MW at December 31, 2008. The decline in the pipeline is primarily due to the transfer of projects into construction and cost containment efforts resulting in the reduction in the number of projects funded under our joint development agreements. EME had purchase contracts for 512 MW of wind turbines for future projects as of December 31, 2009. EME plans to deploy these wind turbines when projects meet acceptable financial thresholds, have long-term power sales agreements, and can attract long-term project financing. If EME is unable to develop such projects on acceptable terms and conditions, certain turbine orders may be terminated. Such an event would likely result in a material charge.
At December 31, 2009, EME had two projects under construction: the 240 MW Big Sky wind project, and the 150 MW Cedro Hill wind project, which are scheduled for completion in
early 2011 and late 2010, respectively. EME has obtained financing for the Big Sky wind project ($206 million). During the first quarter of 2010, EME commenced construction of the 130 MW Taloga wind project located in Oklahoma and executed a power sales agreement for an 80 MW project located in Nebraska, referred to as the Laredo Ridge wind project. After designating turbines for these projects, EME has reduced its available turbines for future projects to 302 MW.
The pace of further growth in EME's renewables program will be subject to availability of projects that meet EME's requirements and the capital needed for development, and it may be affected by future decisions about capital expenditures for environmental compliance by its coal fleet.
The parent company's liquidity and its ability to pay operating expenses and dividends to common shareholders have historically been dependent on dividends from SCE, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to bank and capital markets. During 2009, Edison International paid common dividends of $404 million to its shareholders. Given its subsidiaries' plans to use their current cash flow for their respective capital needs, Edison International (parent) expects to incur additional borrowings to fund its own activities.
At December 31, 2009, Edison International (parent) had approximately $18 million of cash and equivalents on hand. The following table summarizes the status of the Edison International (parent) credit facility at December 31, 2009:
Edison International has a debt covenant in its credit facility that requires a consolidated debt to total capitalization ratio of less than or equal to 0.65 to 1 to be met. At December 31, 2009, Edison International's consolidated debt to total capitalization ratio was 0.53 to 1.
SCE's results of operations are derived mainly through two sources:
Utility earning activities include base rates that are designed to recover forecasted operation and maintenance costs, certain capital-related carrying costs, interest, taxes and a return, including the return on capital projects recovered through balancing account mechanisms. Differences between authorized and actual results impact earnings. Also, included in utility earning activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.
Utility cost-recovery activities include rates which provide for recovery, subject to reasonableness review, of fuel costs, purchased power costs, public purpose related-program costs (including energy efficiency and demand-side management programs), nuclear decommissioning expense, certain operation and maintenance expenses, and depreciation expense related to certain projects. There is no return for cost-recovery expenses.
The following table is a summary of SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities (including Big 4).
Utility earning activities were primarily affected by:
See "Item 8. Edison International Notes to Consolidated Financial StatementsNote 12. Other Income and Expenses" for further detail of other income.
Utility earning activities were primarily affected by:
primarily related to higher labor costs, increased uncollectible accounts and higher franchise fees and higher maintenance costs.
Utility cost-recovery activities were primarily affected by:
higher pension and PBOP expenses of $60 million due to the volatile market conditions experienced in 2008. These increases were partially offset by $50 million of lower energy efficiency costs, $85 million of lower transmission access and reliability service charges and $30 million of lower Mountainview expenses resulting from the transfer of the Mountainview plant to utility rate base in July 2009.
Utility cost-recovery activities were primarily affected by:
SCE's total consolidated operating revenue was $10 billion, $11.2 billion and $10.2 billion for the year-ended December 31, 2009, 2008, and 2007, respectively, of which $9.5 billion, $9.3 billion and $9.2 billion related to retail billed and unbilled revenue (excluding wholesale sales) for the same respective periods. In 2009, retail billed and unbilled revenue increased $184 million compared to the same period in 2008. The increase reflects a rate increase (including impact of a tiered rate structure) of $564 million and a sales volume decrease of $380 million. Effective April 4, 2009, SCE's overall system average rate increased to 14.1¢ per-kWh due to the implementation of both revenue allocation and rate design changes authorized in Phase 2 of the 2009 GRC and the FERC transmission rate changes authorized in the 2009 FERC rate case. The sales volume decrease was due to the economic downturn as well as the impact of milder weather experienced in 2009 compared to the same period in 2008. Retail billed and unbilled revenue increased $94 million in 2008, compared to the same period in 2007. The increase reflects a rate increase (including impact of tiered rate structure) of $92 million and a sales volume increase of $2 million. The rate increase was due to minor variations of usage by rate class.
Due to warmer weather during the summer months and SCE's rate design, operating revenue during the third quarter of each year is generally higher than other quarters.
Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers, CDWR bond-related costs and a portion of direct access exit fees are remitted to the CDWR and are not recognized as revenue by SCE. The amounts collected and remitted to CDWR were $1.8 billion, $2.2 billion and $2.3 billion for the years ended December 31, 2009, 2008 and 2007, respectively.
SCE's effective income tax rate was 16.3% in 2009 compared to 31.8% in 2008. The effective tax rate decreased due to 2009 benefits related to both the Global Settlement and recognition of additional AFUDC equity resulting from the transfer of the Mountainview power plant to utility rate base. Partially offsetting these items was an increase from higher 2008 software deductions related to the implementation of SAP and lower property-related tax benefits in 2009. The effective tax rate for both periods was lower than the federal statutory rate primarily due to these items as well as other property related flow-through items and state income expense. The CPUC requires flow-through rate-making treatment for the current tax benefit arising from certain property-related and other temporary differences, which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense.
SCE's effective income tax rate was 31.8% in 2008 compared to 30.8% in 2007. The 2008 effective tax rate included tax benefits from higher software deductions related to the implementation of SAP. The 2007 effective tax rate included tax benefits from reductions in liabilities for uncertain tax positions to reflect both the progress made in an administrative appeals process with the IRS related to the income tax treatment of certain costs associated with environmental remediation and to reflect a settlement of state tax audit issues. The effective tax rate for both periods was lower than the federal statutory rate primarily due to these items as well as other property related flow-through items and state income tax expense. See "Item 8. Edison International Notes to Consolidated Financial StatementsNote 4. Income Taxes."
SCE's ability to operate its business, complete planned capital projects, and implement its business strategy is dependent upon its cash flow and access to the capital markets to finance its business. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its customers through regulated rates, changes in commodity prices and volumes, collateral requirements, dividend payments made to Edison International, and the outcome of tax and regulatory matters.
SCE's continuing obligations and projected capital investments, both for 2010, are expected to be funded through cash and equivalents on hand, operating cash flows and incremental capital market financings of debt and preferred equity. SCE expects that it would also be able to draw on the remaining availability of its credit facilities and access capital markets if additional funding and liquidity are necessary to meet operating and capital requirements.
As of December 31, 2009, SCE had approximately $3.3 billion of available liquidity comprised of cash and equivalents and short-term investments and $2.9 billion available under credit facilities. As of December 31, 2009, SCE's long-term debt, including current maturities of long-term debt, was $6.7 billion.
The following table summarizes the status of SCE's credit facilities at December 31, 2009:
SCE has a debt covenant in its credit facilities that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At December 31, 2009, SCE's debt to total capitalization ratio was 0.45 to 1.
SCE's capital investment plan for 2010 2014 includes a capital forecast of $21.5 billion. The 2010 2011 planned capital investments for projects under CPUC jurisdiction are recovered through the authorized revenue requirement in SCE's 2009 GRC or through other CPUC-authorized mechanisms. Recovery of planned capital investments for projects under CPUC jurisdiction beyond 2011 and not already approved through other CPUC-authorized mechanisms, is subject to the outcome of future CPUC GRCs or other CPUC approvals. Recovery of the 2010 planned capital investments for projects under FERC jurisdiction has been requested in the 2010 FERC Rate Case. Recovery of the 2011 2014 planned capital investments under FERC jurisdiction will be requested in future FERC transmission filings, as appropriate.
The completion of the projects, the timing of expenditures, and the associated cost recovery may be affected by permitting requirements and delays, construction schedules, availability of labor, equipment and materials, financing, legal and regulatory approvals and developments, weather and other unforeseen conditions.
SCE capital investments (including accruals) related to its 2009 capital plan were $2.9 billion. SCE's capital investments for 2009 were approximately 15% less than the original forecast, primarily due to timing delays resulting from a later than expected 2009 GRC decision and delays in other regulatory approvals. The estimated capital investments for the next five years may vary from SCE's current forecast in a range of $18 billion to $21.5 billion based on the average variability experienced in 2008 and 2009 of 16.5%. Applying the two-year historical average variability to the current forecast, the estimated capital investments for the next five years would vary in the range of: 2010 $3.3 billion to $4.0 billion; 2011 $3.7 billion to $4.4 billion; 2012 $3.9 billion to $4.6 billion; 2013 $3.6 billion to $4.3 billion; and 2014
$3.5 billion to $4.2 billion. SCE's 2009 capital spending and 2010 2014 capital spending forecast is set forth in the following table:
Distribution investments include projects and programs to meet customer load growth requirements, reliability and infrastructure replacement needs, information and other technology and related facility requirements for 2010 2014. Of the total investments, $3.8 billion are recovered through rates authorized in SCE's 2009 CPUC GRC decision, and $7.1 billion are subject to review and approval in the 2012 CPUC GRC proceeding.
SCE's has planned the following significant transmission projects:
In November 2007, the FERC approved a 125 basis point ROE project adder, a 50 basis point adder for CAISO participation, recovery of the ROE and incentive adders during the CWIP phase, and recovery of abandoned plant costs (if any) on the DPV2 project. Various parties have challenged SCE's ability to receive the DPV2 incentives.
San Onofre Steam Generator Replacement Project In February 2010, SCE installed the first two of the four planned steam generators. San Onofre Unit 2 is expected to be back online in March 2010. The steam generator replacement project is intended to enable San Onofre to operate until the end of its initial license period in 2022, and beyond if license renewal proves feasible. SCE expects to spend $270 million over