UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________________
FORM 10-K
________________________
(Mark One) | |
R | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2011 | |
o | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to | |
Commission File Number 1-9936
_________________________
EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)
__________________________
California | 95-4137452 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
2244 Walnut Grove Avenue (P.O. Box 976) Rosemead, California | 91770 (Zip Code) | |
(Address of principal executive offices) | ||
(626) 302-2222 (Registrant's telephone number, including area code) | ||
Securities registered pursuant to Section 12(b) of the Act:
Title of each class | Name of each exchange on which registered | |||
Common Stock, no par value | NYSE | |||
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 $12.6 billion on or about June 30, 2011, based upon prices reported on the New York Stock Exchange. As of February 27, 2012, 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.
(1) Designated portions of the Proxy Statement relating to registrant's 2012 Annual Meeting of Shareholders Part III
TABLE OF CONTENTS
i
ii
iii
iv
GLOSSARY
The following terms and abbreviations appearing in the text of this report have the meanings indicated below.
2011 Form 10-K | Edison International's Annual Report on Form 10-K for the year-ended December 31, 2011 | |
2010 Tax Relief Act | Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010 | |
AFUDC | allowance for funds used during construction | |
Ambit project | American Bituminous Power Partners, L.P. | |
AOI | Adjusted Operating Income (Loss) | |
APS | Arizona Public Service Company | |
ARO(s) | asset retirement obligation(s) | |
BACT | best available control technology | |
BART | best available retrofit technology | |
Bcf | billion cubic feet | |
Big 4 | Kern River, Midway-Sunset, Sycamore and Watson natural gas power projects | |
Btu | British thermal units | |
CAA | Clean Air Act | |
CAIR | Clean Air Interstate Rule | |
CAISO | California Independent System Operator | |
CAMR | Clean Air Mercury Rule | |
CARB | California Air Resources Board | |
CDWR | California Department of Water Resources | |
CEC | California Energy Commission | |
coal plants | Midwest Generation coal plants and Homer City plant | |
Commonwealth Edison | Commonwealth Edison Company | |
CPS | Combined Pollutant Standard | |
CPUC | California Public Utilities Commission | |
CSAPR | Cross-State Air Pollution Rule | |
CRRs | congestion revenue rights | |
DOE | U.S. Department of Energy | |
EME | Edison Mission Energy | |
EMG | Edison Mission Group Inc. | |
EMMT | Edison Mission Marketing & Trading, Inc. | |
EPS | earnings per share | |
ERRA | energy resource recovery account | |
Exelon Generation | Exelon Generation Company LLC | |
FASB | Financial Accounting Standards Board | |
FERC | Federal Energy Regulatory Commission | |
FGIC | Financial Guarantee Insurance Company | |
FIP(s) | federal implementation plan(s) | |
Four Corners | coal fueled electric generating facility located in Farmington, New Mexico in which SCE holds a 48% ownership interest | |
GAAP | generally accepted accounting principles | |
GHG | greenhouse gas | |
Global Settlement | A settlement between Edison International and the IRS that resolved federal tax disputes related to Edison Capital's cross-border, leveraged leases through 2009, and all other outstanding federal tax disputes and affirmative claims for tax years 1986 through 2002 and related matters with state tax authorities. | |
v
GRC | general rate case | |
GWh | gigawatt-hours | |
Homer City | EME Homer City Generation L.P., a Pennsylvania limited partnership that leases and operates three coal-fired electric generating units and related facilities located in Indiana County, Pennsylvania | |
Illinois EPA | Illinois Environmental Protection Agency | |
IRS | Internal Revenue Service | |
ISO | Independent System Operator | |
kWh(s) | kilowatt-hour(s) | |
LIBOR | London Interbank Offered Rate | |
MATS | Mercury and Air Toxics Standards | |
MD&A | Management's Discussion and Analysis of Financial Condition and Results of Operations in this report | |
Midwest Generation | Midwest Generation, LLC, a Delaware limited liability company that owns and/or leases, and that operates, the Midwest Generation plants | |
Midwest Generation plants | Midwest Generation's power plants (fossil fuel) located in Illinois | |
MMBtu | million British thermal units | |
Mohave | two coal fueled electric generating facilities that no longer operate located in Clark County, Nevada in which SCE holds a 56% ownership interest | |
Moody's | Moody's Investors Service | |
MRTU | Market Redesign and Technology Upgrade | |
MW | megawatts | |
MWh | megawatt-hours | |
NAAQS | national ambient air quality standards | |
NAPP | Northern Appalachian | |
NERC | North American Electric Reliability Corporation | |
Ninth Circuit | U.S. Court of Appeals for the Ninth Circuit | |
NOV | notice of violation | |
NOx | nitrogen oxide | |
NRC | Nuclear Regulatory Commission | |
NSR | New Source Review | |
NYISO | New York Independent System Operator | |
PADEP | Pennsylvania Department of Environmental Protection | |
Palo Verde | large pressurized water nuclear electric generating facility located near Phoenix, Arizona in which SCE holds a 15.8% ownership interest | |
PBOP(s) | postretirement benefits other than pension(s) | |
PBR | performance-based ratemaking | |
PG&E | Pacific Gas & Electric Company | |
PJM | PJM Interconnection, LLC | |
PRB | Powder River Basin | |
PSD | Prevention of Significant Deterioration | |
QF(s) | qualifying facility(ies) | |
ROE | return on equity | |
RPM | Reliability Pricing Model | |
RTO(s) | Regional Transmission Organization(s) | |
S&P | Standard & Poor's Ratings Services | |
San Onofre | large pressurized water nuclear electric generating facility located in south San Clemente, California in which SCE holds a 78.21% ownership interest | |
vi
SCE | Southern California Edison Company | |
SNCR | selective non-catalytic reduction | |
SDG&E | San Diego Gas & Electric | |
SEC | U.S. Securities and Exchange Commission | |
SIP(s) | state implementation plan(s) | |
SO2 | sulfur dioxide | |
US EPA | U.S. Environmental Protection Agency | |
VIE(s) | variable interest entity(ies) | |
vii
FORWARD-LOOKING STATEMENTS
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:
• | cost of capital and the ability of Edison International or its subsidiaries to borrow funds and access the capital markets on reasonable terms; |
• | environmental laws and regulations, at both state and federal levels, or changes in the application of those laws, that could require additional expenditures or otherwise affect the cost and manner of doing business, including compliance with CPS at Midwest Generation and the CSAPR and the MATS rule at Midwest Generation and Homer City; |
• | ability of SCE to recover its costs in a timely manner from its customers through regulated rates; |
• | decisions and other actions by the CPUC, the FERC and other regulatory authorities and delays in regulatory actions; |
• | possible customer bypass or departure due to technological advancements or cumulative rate impacts that make self-generation or use of alternative energy sources economically viable; |
• | risks associated with the operation of transmission and distribution assets and nuclear and other power generating facilities including: nuclear fuel storage issues, public safety issues, failure, availability, efficiency, output, cost of repairs and retrofits of equipment and availability and cost of spare parts; |
• | cost and availability of electricity, including the ability to procure sufficient resources to meet expected customer needs in the event of significant counterparty defaults under power-purchase agreements; |
• | changes in the fair value of investments and other assets; |
• | changes in interest rates and rates of inflation, including those rates which may be adjusted by public utility regulators; |
• | governmental, statutory, regulatory or administrative changes or initiatives affecting the electricity industry, including the market structure rules applicable to each market and price mitigation strategies adopted by Independent System Operators and Regional Transmission Organizations; |
• | availability and creditworthiness of counterparties and the resulting effects on liquidity in the power and fuel markets and/or the ability of counterparties to pay amounts owed in excess of collateral provided in support of their obligations; |
• | cost and availability of labor, equipment and materials; |
• | ability to obtain sufficient insurance, including insurance relating to SCE's nuclear facilities and wildfire-related liability, and to recover the costs of such insurance; |
• | ability to recover uninsured losses in connection with wildfire-related liability; |
• | effects of legal proceedings, changes in or interpretations of tax laws, rates or policies, and changes in accounting standards; |
• | potential for penalties or disallowances caused by non-compliance with applicable laws and regulations; |
• | cost and availability of coal, natural gas, fuel oil, and nuclear fuel, and related transportation to the extent not recovered through regulated rate cost escalation provisions or balancing accounts; |
1
• | cost and availability of emission credits or allowances for emission credits; |
• | transmission congestion in and to each market area and the resulting differences in prices between delivery points; |
• | ability to provide sufficient collateral in support of hedging activities and power and fuel purchased; |
• | risks inherent in the development of generation projects and transmission and distribution infrastructure replacement and expansion projects, including those related to project site identification, public opposition, environmental mitigation, construction, permitting, power curtailment costs (payments due under power contracts in the event there is insufficient transmission to enable the acceptance of power delivery), and governmental approvals; |
• | risks that competing transmission systems will be built by merchant transmission providers in SCE's service area; and |
• | weather conditions and natural disasters. |
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.
2
PART I
ITEM 1. BUSINESS
INTRODUCTION
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 and Edison Mission Group Inc. ("EMG"), a competitive power generation company. As a holding company, Edison International's progress and outlook are dependent on developments at its operating subsidiaries.
At December 31, 2011, Edison International and its subsidiaries had an aggregate of 19,930 full-time employees. 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.
Subsidiaries of Edison International
Edison International has two business segments for financial reporting purposes: an electric utility segment (SCE) and a competitive power generation segment (EMG).
SCE is an investor-owned public utility primarily engaged in the business of supplying electricity to an approximately 50,000 square-mile area of southern California. The SCE service territory contains a population of nearly 14 million people. In 2011, SCE's total operating revenue was derived as follows: 41.6% commercial customers, 40.2% residential customers, 5.7% industrial customers, 0.7% resale sales, 5.5% public authorities, and 6.3% agricultural and other customers. SCE had 18,069 full-time employees at December 31, 2011. SCE's operating revenue was approximately $10.6 billion in 2011.
Sources of energy to serve SCE's customers during 2011 were approximately: 36% purchased power; 21% CDWR; and 43% SCE-owned generation.
SCE separately files reports pursuant to Section 13(a) or 15(d) of the Securities Exchange Act. SCE also files a joint Proxy Statement with its parent, Edison International. Such reports and Proxy Statement are available at www.edisoninvestor.com or on the SEC's 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 subsidiary, EME. EME is also 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. Some of the facilities are operated on a merchant basis, with energy being sold into the marketplace, and others are operated under contracts calling for the delivery of energy to specific purchasers. EME also engages in hedging and energy trading activities in competitive power markets through its Edison Mission Marketing & Trading, Inc. ("EMMT") subsidiary. At December 31, 2011, EMG and its subsidiaries employed 1,795 people. EMG's consolidated operating revenue was approximately $2.2 billion in 2011.
EMG's subsidiaries or affiliates have typically been formed to own full or partial interests in one or more power generation facilities and ancillary facilities, with each plant or group of related plants being individually referred to by EMG as a project. EMG's operating projects primarily consist of coal-fired and natural gas-fired generating facilities, and renewable energy facilities, primarily wind projects. As of December 31, 2011, EMG's subsidiaries and affiliates owned or leased interests in 43 operating projects with an aggregate net physical capacity of 11,504 MW of which EME's pro rata share was 10,379 MW. At December 31, 2011, EME's subsidiaries and affiliates also had one wind project and one natural gas-fired peaker plant under construction, totaling 80 MW and 479 MW, respectively of net generating capacity.
EME separately files reports pursuant to Section 13(a) or 15(d) of the Securities Exchange Act. Such reports are 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.
Edison International maintains a property and casualty insurance program for itself and its subsidiaries, which includes
3
business interruption (for EMG only), and excess liability insurance covering liabilities to third parties for bodily injury or property damage resulting from operations. These policies are subject to specific retentions, sublimits and deductibles, which are comparable to those carried by other utility and electric generating companies of similar size. SCE also has separate insurance programs for nuclear property and liability, workers compensation and solar rooftop construction. EMG maintains a separate wind liability insurance program for its wind projects. For further information on wildfire insurance, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
Regulation of Edison International and Subsidiaries
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 Public Utility Holding Company Act 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.
Edison International is not a public utility. The 1988 CPUC decision authorizing SCE to reorganize into a holding company structure, however, contains certain obligations on Edison International and its affiliates. These include a requirement 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, among other requirements, prohibit holding companies from (1) being used as a conduit to provide non-public information to a utility's affiliate and (2) causing or abetting a utility's violation of the rules, including providing preferential treatment to affiliates.
SOUTHERN CALIFORNIA EDISON COMPANY
Regulation
CPUC
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 funding and costs, and aspects of the transmission system planning, site identification and construction.
FERC
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 FERC also has jurisdiction over a portion of the retail rates and associated rate design.
NERC
The North American Electric Reliability Corporation ("NERC") establishes and enforces reliability standards and critical infrastructure protection standards to protect the bulk power system against potential disruptions from cyber and physical security breaches. The critical infrastructure protection standards focus on controlling access to critical physical and cyber security assets. Compliance with these standards is mandatory. The maximum penalty that may be levied for violating a NERC reliability or critical infrastructure protection standard is $1 million per violation, per day.
SCE has a formal cyber security program that is staffed and has a dedicated budget. The program covers SCE's information technology systems as well as the electric grid where SCE has control of it. Program staff is engaged with industry groups as well as public-private initiatives to reduce risk and to strengthen the security and reliability of SCE's systems and infrastructure. The program is also engaged in the protection of SCE's customer information.
Transmission and Substation Facilities Regulation
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 CAISO, 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
4
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 are also necessary for the project to proceed.
CEC
The construction, planning, and project site identification of SCE's power plants of 50 MW or greater within California are subject to the jurisdiction of the CEC. The CEC is also responsible for forecasting future energy needs. These forecasts are used by the CPUC in determining the adequacy of SCE's electricity procurement plans.
Nuclear Power Plant Regulation
SCE is subject to the jurisdiction of the NRC with respect to the safety of its San Onofre and Palo Verde Nuclear Generating Stations. The NRC regulates commercial nuclear power plants through licensing, oversight and inspection, performance assessment, and enforcement of its requirements.
In light of the events at the Fukushima Daiichi nuclear plant in Japan resulting from the March 2011 earthquake and tsunami, the NRC has been performing and plans to continue to perform additional operational and safety reviews of nuclear facilities in the United States. The NRC's Near Term Task Force ("NTTF") conducted a systematic review of NRC processes and regulations to determine whether additional improvements to the existing nuclear regulatory system are warranted in light of the events in Japan. The NTTF concluded that a sequence of events like the Fukushima accident is unlikely to occur in the U.S., and that continued operation of U.S. reactors does not pose an imminent risk to public health and safety. The NTTF Report proposed changes to regulations applicable to protection against natural phenomena, including earthquakes and flooding and emergency preparedness, and the NTTF made a number of recommendations as to actions that the NRC might implement. In October 2011, the NRC identified seven of the near-term actions recommended by the NRC staff as having the greatest potential for safety improvement. The NRC staff was directed to strive to implement these actions by 2016. Implementation of these actions will require further interactions between the NRC staff and the nuclear industry. These actions may impact future operations and capital requirements at U.S. nuclear facilities at the time of their implementation, including the operations and capital requirements of SCE's nuclear facilities.
Operating License Renewal
In April 2011, the NRC extended the operating license for Palo Verde Operating Units 1, 2 and 3 for an additional 20 years, to 2045, 2046 and 2047, respectively. San Onofre's current operating licenses for Units 2 and 3 will expire in 2022. The NRC's review of a license renewal application typically takes three to five years. Prior to filing a license renewal application at the NRC, SCE would make an application to the CPUC to demonstrate the cost effectiveness of continuing operations at San Onofre and to seek authority to recover the cost of seeking a license renewal at the NRC and pursuing approvals from other state and federal agencies, such as the Department of the Navy and the California Coastal Commission. SCE will consider a decision to file an application for cost recovery at the CPUC in 2012. If SCE were to choose not to pursue license renewal or if SCE' efforts to obtain license renewal were not successful, SCE will need to determine what generation and transmission alternatives would need to be made available to replace the capacity, energy, and grid reliability benefits that SCE's customers now receive from San Onofre by the time San Onofre ceases generating electricity. Should SCE decide to pursue a license extension for San Onofre, SCE will likely need to simultaneously consider generation and transmission alternatives given the long lead times for the NRC to approve a license extension and to site, permit and construct new generation and transmission facilities. The costs of these alternatives could be substantial.
Overview of Ratemaking Process
CPUC
Revenue authorized by the CPUC through triennial GRC proceedings is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation and distribution assets (also referred to as “rate base”). The CPUC sets an annual revenue requirement for the base year which is made up of the operation and maintenance costs, depreciation, taxes and a return consistent with the capital structure (discussed below). The return is established by multiplying an authorized rate of return, determined in separate cost of capital proceedings, by SCE's generation and distribution rate base. In the GRC proceedings, the CPUC also generally approves the level of capital spending on a forecast basis. Following the base year, the revenue requirements for the remaining two years are set by a methodology established in the GRC proceeding, which generally, among other items, includes annual allowances for escalation in operation and maintenance costs, additional changes in capital-related investments and the recovery for expected nuclear refueling outages.
SCE's authorized revenue requirements were $4.83 billion, $5.04 billion and $5.25 billion for the years ended December 31, 2009, 2010 and 2011, respectively. SCE filed its 2012 GRC application with the CPUC on November 23, 2010, to be
5
effective on January 1, 2012. For further discussion of the 2012 GRC, see "Edison International Overview—Management Overview of SCE—2012 CPUC General Rate Case" in the MD&A.
CPUC rates decouple authorized revenue from the volume of electricity sales, so that SCE earns revenue equal to amounts authorized. Differences between amounts collected and authorized levels are either collected from or refunded to customers, and, therefore, such differences do not impact operating revenue. Accordingly, SCE is neither benefited nor burdened by the volumetric risk related to retail 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%, cost of preferred equity of 6.01% and return on common equity of 11.5%. SCE is scheduled to file a new cost of capital application with the CPUC in April 2012 that will be effective beginning in 2013.
In addition, to the ratemaking process described above, the CPUC has also authorized ratemaking mechanisms outside of the GRC process for significant capital projects, as needed.
Balancing accounts (also referred to as cost-recovery mechanisms) are typically used to track and recover SCE's costs of fuel, purchased-power, and certain operation and maintenance expenses, including certain demand-side management program costs. SCE earns no return on these activities and although differences between forecasted and actual costs do not impact earnings, such differences do impact cash flows and can change rapidly.
SCE's balancing account for fuel and power procurement-related costs is established under the Energy Resource Recovery Account ("ERRA") Mechanism. SCE sets rates based on an annual forecast of the costs that it expects to incur during the following year. In addition, 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 revenue that is classified as generation for retail rates. For 2012, the trigger amount is approximately $237 million.
The majority of costs eligible for recovery through cost-recovery rates are approved upfront by the CPUC though a procurement plan with predefined standards, or through CPUC preapproval, and thus could negatively impact earnings and cash flows if SCE's costs were found to be unreasonable or out of compliance and disallowed.
FERC
Revenue authorized by the FERC is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in transmission assets. In August 2011, the FERC accepted SCE's request to implement a formula rate effective January 1, 2012 to determine SCE's FERC transmission revenue requirement, including its construction work in progress ("CWIP") revenue requirement that was previously recovered through a separate mechanism. For further discussion of SCE's FERC formula rates, see "Edison International Overview—Management Overview of SCE—FERC Formula Rates" in the MD&A.
Retail Rates
To develop retail rates, the authorized revenue requirements are allocated among all customer classes (residential, commercial, industrial and agricultural) on a functional basis (i.e., generation, distribution, transmission, etc.). Specific rate components are designed to recover the authorized revenue allocated to each customer class.
Currently, SCE has a five tier residential rate structure. Each tier represents a certain electricity usage level and within each increasing usage level, the electricity is priced at higher rates per kilowatt hour. The first tier is a baseline tier and has the lowest rate per kilowatt hour. "Baseline" refers to a specific amount of energy allocated for residential customers that is charged at a lower price than energy used in excess of that amount. Baseline quantities are determined by SCE for approval by the CPUC using average residential electricity consumption for nine geographical regions in southern and central California. Seasonal variations in usage are also accounted for in determining baseline allowances.
The intent of the baseline and the tiered structure is to provide a portion of reasonable energy needs (baseline usage) of residential customers at the lowest rate, and to encourage conservation of energy by increasing the rate charges as energy usage increases. Statutory restrictions on tier one and two rates have shifted the burden of residential rate increases to the higher tier/usage customers. As part of the second phase of SCE's 2012 GRC, SCE requested certain rate design modifications that are intended to provide a more equitable, cost-based rate design.
CDWR-Related Rates
As a result of the California energy crisis, in 2001 the CDWR entered into contracts to purchase power for sale at cost
6
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 were allocated by the CPUC among the customers of the investor-owned utilities (SCE, PG&E and SDG&E). SCE billed and collected from its customers the costs of power purchased and sold by the CDWR. SCE will continue to bill and collect CDWR bond-related charges and direct access exit fees until 2022. 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 operating revenue; but did affect customer rates. All CDWR power contracts that were allocated to SCE expired by the end of 2011. See "SCE: Results of Operations—Supplemental Operating Revenue Information" in the MD&A for further discussion of the impact of CDWR charges on customer rates.
Purchased Power and Fuel Supply
SCE obtains the power needed to serve its customers from its generating facilities and from sales by qualifying facilities, independent power producers, renewable power producers, the CAISO, and other utilities.
Natural Gas Supply
SCE requires natural gas to meet contractual obligations for power tolling agreements (power contracts in which SCE has agreed to provide or pay for the natural gas burned to generate electricity). SCE also requires natural gas to fuel its Mountainview and peaker plants, which are generation units that are designed to operate in response to changes in demand for power. The physical natural gas purchased by SCE is subject to competitive bidding.
Nuclear Fuel Supply
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:
Uranium concentrates | 2020 |
Conversion | 2020 |
Enrichment | 2020 |
Fabrication | 2015 |
For Palo Verde, contractual arrangements are in place covering 100% of the projected nuclear fuel requirements through the years indicated below:
Uranium concentrates | 2017 |
Conversion | 2018 |
Enrichment | 2020 |
Fabrication | 2016 |
Coal Supply
On January 1, 2010, SCE and the other Four Corners participants entered into a Four Corners Coal Supply 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 co-owners of Four Corners (excluding SCE) are currently negotiating a potential new Coal Supply Agreement with BHP Navajo Coal Company for the period after July 6, 2016. In November 2010, SCE entered into an agreement to sell its interest in Four Corners subject to certain conditions and regulatory approvals. See "Item 8. Edison International Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment," for more information on the sale of SCE's interest in Four Corners.
CAISO Wholesale Energy Market
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. The CAISO schedules 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. SCE participates in the day-ahead and real-time markets for the sale of its generation and purchases of its load requirements.
The CAISO uses a nodal locational pricing model, which sets wholesale electricity prices at system points ("nodes") that
7
reflect local generation and delivery costs. 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 into, 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 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.
Competition
Because SCE is an electric utility company operating within a defined service territory pursuant to authority from the CPUC, SCE faces retail 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 statute 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. Competition between SCE and other electricity providers is conducted mainly on the basis of price; customers seek the lowest cost power available. The effect of this competition on SCE generally is to reduce the number of customers purchasing power from SCE, but those departing customers typically continue to utilize and pay for SCE's transmission and distribution services.
Technological developments, such as on-site power generation (self generation), pose additional competitive challenges for traditional utilities. See "Item 1A. Risk Factors—Risks Relating to SCE—Regulatory Risks." In the area of transmission infrastructure, SCE may experience increased competition from merchant transmission providers. The FERC has made changes to its transmission planning requirements with the goal of opening transmission development to competition from independent developers. In July 2011, the FERC adopted new rules that remove incumbent public utility transmission owners' federally-based right of first refusal to construct certain new transmission facilities. The rules direct regional entities, such as ISOs, to create new processes that would allow other providers to develop new transmission projects. The new processes will not become effective until approved by the FERC, which is expected in late 2012. The majority of SCE's 2012 – 2014 transmission capital forecast relates to transmission projects that have been approved by the CAISO and barring a re-evaluation under the new rules, will not be subject to the new processes. SCE does not expect these projects to be re-evaluated. The impact of the new rules on future transmission projects will depend on the processes ultimately implemented by regional entities.
Properties
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 lines ranging from 33 kV to 500 kV and substations. SCE's distribution system, which takes power from substations to customers, includes over 59,000 circuit miles of overhead lines, 44,000 circuit miles of underground lines and over 700 distribution substations, all of which are located in California.
8
SCE owns the generating facilities listed in the following table.
Generating Facility | Location (in CA, unless otherwise noted) | Fuel Type | Operator | SCE's Ownership Interest (%) | Net Physical Capacity (in MW) | SCE's Capacity pro rata share (in MW) | |||||||||
San Onofre Nuclear Generating Station | South of San Clemente | Nuclear | SCE | 78.21 | % | 2,150 | 1,760 | ||||||||
Hydroelectric Plants (36) | Various | Hydroelectric | SCE | 100 | % | 1,176 | 1,176 | ||||||||
Pebbly Beach Generating Station | Catalina Island | Diesel | SCE | 100 | % | 9 | 9 | ||||||||
Mountainview | Redlands | Natural Gas | SCE | 100 | % | 1,050 | 1,050 | ||||||||
Peaker Plants (4) | Various | Gas fueled Combustion Turbine | SCE | 100 | % | 196 | 196 | ||||||||
Palo Verde Nuclear Generating Station | Phoenix, AZ | Nuclear | APS | 15.8 | % | 3,739 | 591 | ||||||||
Four Corners Units 4 and 5 | Farmington, NM | Coal-fired | APS | 48 | % | 1 | 1,540 | 739 | |||||||
Solar PV Plants (23) | Various | Photovoltaic | SCE | 100 | % | 53 | 53 | ||||||||
Total | 9,913 | 5,574 | |||||||||||||
1 | In November 2010, SCE entered into an agreement to sell its interest in Four Corners to APS for approximately $294 million. The sale is contingent upon the satisfaction of several conditions and the obtaining of multiple regulatory approvals. Currently SCE estimates that the sale will close in the second half of 2012. See "Item 8. Edison International Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment" for more information. |
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.
Twenty-eight 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 2012 and 2046. 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. See "Item 8. Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."
Seasonality
Due to warm weather during the summer months and SCE's rate design, operating revenue during the third quarter of each year is generally higher than the other quarters.
9
EDISON MISSION GROUP INC.
Overview
EMG's competitive power generation business primarily consists of the generation and sale into the PJM market of energy and capacity from merchant coal-fired power plants and a portfolio of natural gas and wind projects. EMG's operating results were significantly lower in 2011 compared to 2010 due to lower realized energy and capacity prices and generation at the coal plants.
At December 31, 2011, EME had corporate cash and cash equivalents of $951 million and $498 million of available borrowing capacity under its $564 million revolving credit facility maturing in June 2012 and Midwest Generation had cash and cash equivalents of $213 million and $497 million of available borrowing capacity under its $500 million credit facility maturing in June 2012. Subsequent to the end of the fiscal year, EME terminated its revolving credit facility and there can be no assurance that Midwest Generation will be eligible to draw on its credit facility prior to maturity. Any replacements of these credit lines will likely be on less favorable terms and conditions, and there is no assurance that EME will, or will be able to, replace these credit lines or any portion of them. EME had $3.7 billion of unsecured notes outstanding at December 31, 2011, $500 million of which mature in 2013. Unless energy and capacity prices increase, EME expects that it will experience further reductions in cash flow and losses in 2012 and subsequent years. EME's liquidity will be strained by a continuation of recent adverse trends, combined with pending debt maturities, higher operating costs and the need to retrofit its coal-fired plants to comply with governmental regulations. To address such a scenario, EME would need to consider all options available to it, including potential sales of assets or restructurings or reorganization of the capital structure of EME and its subsidiaries.
Homer City failed to obtain sufficient interest from market participants to fund the capital improvements during the process undertaken in the fourth quarter of 2011. Homer City is currently engaged in discussions with the owner-lessors regarding the potential for such funding. EME expects that the outcome of any such discussions, if successful in providing funding for the Homer City plant, will likely result in EME's loss of substantially all beneficial economic interest in and material control of the Homer City plant. Failure to resolve the source of funding of necessary capital expenditures for the Homer City plant could result in Homer City's default under the lease agreements giving rise to remedies for the owner-lessors and secured lease obligation bondholders, which could include foreclosing on the leased assets, the general partner of Homer City, or both. For further discussion of these matters, see "Edison International Overview—Management Overview of EMG" in the MD&A.
Regulation
Federal Power Act
The FERC has 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. The FERC also has 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. Dispositions of EMG's jurisdictional assets and certain types of financing arrangements may require FERC approval.
Each of EMG's domestic generating facilities is either a qualifying facility, as determined by the FERC, or the subsidiary owning the facility is an exempt wholesale generator. Most qualifying facilities, including EMG's qualifying facilities, are exempt from the ratemaking and several other provisions of the Federal Power Act. EMG's exempt wholesale generators are subject to the FERC's ratemaking jurisdiction under the Federal Power Act, but have been authorized by the FERC to sell power at market-based rates. In addition, EMG'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 FERC ratemaking regulation under the Federal Power Act.
If one of the projects in which EMG has an interest were to lose its qualifying facility or exempt wholesale generator status, the project would no longer be entitled to the related exemptions from regulation and could become subject to rate regulation by the FERC and state authorities. Loss of status could also trigger defaults under covenants contained in the project's power sales agreements and financing agreements.
Transmission of Wholesale Power
EMG's projects that sell power to wholesale purchasers other than the local utility to which the project may be interconnected require the transmission of electricity over power lines owned by others. The prices and other terms and conditions of
10
transmission contracts are regulated by the FERC when the entity providing the transmission service is subject to FERC jurisdiction.
Markets for Generation
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. 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 addition, capacity markets in various regional wholesale power markets compensate supply resources for the capability to supply electricity when needed, and demand resources, for electricity they avoid using.
Wholesale Markets
EMG's largest power plants are its coal power plants located in Illinois, which are collectively referred to as the Midwest Generation plants, and the Homer City plant located in Pennsylvania. Collectively, both the Midwest Generation plants and the Homer City plant are referred to as the coal plants in this annual report. The coal plants 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. Sales may also be made from PJM into the Midwest Independent Transmission System Operator ("MISO") RTO, which includes all or parts of Illinois, Wisconsin, Indiana, Michigan, Ohio and other states in the region, and into the NYISO, which controls the transmission grid and energy and capacity markets for New York State.
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 requires all load-serving entities and generators, such as Midwest Generation and Homer City, to maintain prescribed levels of capacity, including a reserve margin, to ensure system reliability. PJM's capacity markets have a single market-clearing price for each capacity zone. In May of each year, PJM conducts an annual capacity auction ("RPM") to commit generation, energy efficiency and demand side resources three years forward, and to provide a long-term pricing signal for the construction of capacity resources.
Fuel Supply
The Midwest Generation plants purchase coal from several suppliers located in the Southern PRB of Wyoming. The total volume of coal consumed annually is largely dependent on the amount of generation and has historically ranged between 17 million to 19 million tons. Coal consumption in the current low natural gas price environment may be lower than the historical range. Coal is transported under transportation agreements with Union Pacific Railroad and various short-line carriers. In late 2011, Midwest Generation signed new agreements, effective January 1, 2012, to provide fuel transportation on a long-term basis. For additional information, see "EMG: Results of Operations—Market Risk Exposures—Commodity Price Risk—Coal and Transportation Risk" in the MD&A. As of December 31, 2011, Midwest Generation leased approximately 3,400 railcars to transport the coal from the mines to the generating stations, under leases with remaining terms that range from less than one year to eight years, with options to extend the leases or purchase some railcars at the end of the lease terms.
Homer City's Units 1 and 2 have historically consumed approximately 2.8 million to 3.3 million tons of mid-range sulfur coal per year. Two types of coal are purchased, ready-to-burn and raw coal. Ready-to-burn coal is of the quality that can be burned directly in Units 1 and 2, whereas the raw coal purchased for consumption by Units 1 and 2 must be cleaned in the Homer City coal cleaning facility, which has the capacity to clean up to 5 million tons of coal per year. Unit 3 has historically consumed approximately 1.5 million to 2 million tons of coal per year and can consume either raw or ready-to-burn coal. Coal consumption in the current low natural gas price environment may be lower than the historical range. A wet scrubber FGD system for Unit 3 enables this unit to burn less expensive, higher sulfur coal, while still meeting environmental standards for emission control. In general, the coal purchased for all three units is acquired locally. For additional information, see "Edison International Overview—Management Overview of EMG" and "EMG: Results of Operations—Market Risk Exposures—Commodity Price Risk—Coal and Transportation Risk" in the MD&A.
11
Competition
EMG is subject to competition from energy marketers, public utilities, government-owned power agencies, industrial companies, financial institutions, and other independent power producers. These companies may have competitive advantages as a result of scale, the location of their generation facilities, or other factors. Some of EMG's competitors have a lower cost of capital than EMG and, in the case of utilities, may be 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.
State and local environmental regulations, particularly those that impose stringent state-specific emission limits in Illinois, could put EMG's coal plants at a disadvantage compared with competing power plants operating in nearby states and subject to less stringent state emission limits or to federal emission limits alone. The CPS puts the Midwest Generation plants at a disadvantage compared with competing plants not subject to similar regulations, and federal air quality regulations such as CSAPR and the MATS rule will put EMG's coal plants, particularly Homer City, at a disadvantage compared to plants utilizing other fuels. Potential future climate change regulations could also put EME's coal plants at a disadvantage compared to power plants utilizing other fuels as well as utilities that can also be able to recover climate change compliance costs through rate base mechanisms. The ability of EMG's coal plants to compete may be affected by future environmental regulations, by governmental and regulatory activities designed to support the construction and operation of power generation facilities fueled by renewable energy sources, and by developments such as shale gas technology that lower the price of other fuels.
12
Properties
Power Plants in Operation
As of December 31, 2011, EMG's operations consisted of ownership or leasehold interests in the following operating projects
Power Plants | Location | Primary Electric Purchaser2 | Fuel Type | EMG's Ownership Interest | Net Physical Capacity (in MW) | EMG's Capacity Pro Rata Share (in MW) | |||||||||
MERCHANT POWER PLANTS | |||||||||||||||
Midwest Generation plants1 | Illinois | PJM | coal | 100 | % | 5,172 | 5,172 | ||||||||
Midwest Generation plants1 | Illinois | PJM | oil | 100 | % | 305 | 305 | ||||||||
Homer City plant1 | Pennsylvania | PJM | coal | 100 | % | 1,884 | 1,884 | ||||||||
Merchant Wind | |||||||||||||||
Goat Wind | Texas | ERCOT | wind | 99.9 | % | 3 | 150 | 150 | |||||||
Lookout | Pennsylvania | PJM | wind | 100 | % | 38 | 38 | ||||||||
Big Sky | Illinois | PJM | wind | 100 | % | 240 | 240 | ||||||||
CONTRACTED POWER PLANTS – Domestic | |||||||||||||||
Natural Gas | |||||||||||||||
Big 4 Projects | |||||||||||||||
Kern River1 | California | SCE | natural gas | 50 | % | 300 | 150 | ||||||||
Midway-Sunset1 | California | PG&E | natural gas | 50 | % | 225 | 113 | ||||||||
Sycamore1 | California | SCE | natural gas | 50 | % | 300 | 150 | ||||||||
Watson | California | SCE | natural gas | 49 | % | 385 | 189 | ||||||||
Westside Projects (4)1 | California | PG&E | natural gas | 50 | % | 152 | 76 | ||||||||
Sunrise1 | California | CDWR | natural gas | 50 | % | 572 | 286 | ||||||||
Renewable Energy | |||||||||||||||
Buffalo Bear | Oklahoma | WFEC | wind | 100 | % | 19 | 19 | ||||||||
Cedro Hill | Texas | CSA | wind | 100 | % | 150 | 150 | ||||||||
Community Wind North | Minnesota | NSPC | wind | 99 | % | 30 | 30 | ||||||||
Crosswinds | Iowa | CBPC | wind | 99 | % | 3 | 21 | 21 | |||||||
Elkhorn Ridge | Nebraska | NPPD | wind | 67 | % | 80 | 53 | ||||||||
Forward | Pennsylvania | CECG | wind | 100 | % | 29 | 29 | ||||||||
Hardin | Iowa | IPLC | wind | 99 | % | 3 | 15 | 15 | |||||||
High Lonesome | New Mexico | APSC | wind | 100 | % | 100 | 100 | ||||||||
Jeffers | Minnesota | NSPC | wind | 99.9 | % | 3 | 50 | 50 | |||||||
Laredo Ridge | Nebraska | NPPD | wind | 100 | % | 80 | 80 | ||||||||
Minnesota Wind projects4 | Minnesota | NSPC/IPLC | wind | 75-99% | 3 | 73 | 67 | ||||||||
Mountain Wind I | Wyoming | PC | wind | 100 | % | 61 | 61 | ||||||||
Mountain Wind II | Wyoming | PC | wind | 100 | % | 80 | 80 | ||||||||
Odin | Minnesota | MRES | wind | 99.9 | % | 3 | 20 | 20 | |||||||
Pinnacle5 | West Virginia | MDGS/USM | wind | 100 | % | 55 | 55 | ||||||||
San Juan Mesa | New Mexico | SPS | wind | 75 | % | 120 | 90 | ||||||||
Sleeping Bear | Oklahoma | PSCO | wind | 100 | % | 95 | 95 | ||||||||
Spanish Fork | Utah | PC | wind | 100 | % | 19 | 19 | ||||||||
Storm Lake1 | Iowa | MEC | wind | 100 | % | 108 | 108 | ||||||||
Taloga | Oklahoma | OGEC | wind | 100 | % | 130 | 130 | ||||||||
Wildorado | Texas | SPS | wind | 99.9 | % | 3 | 161 | 161 | |||||||
Huntington Waste-to-Energy | New York | LIPA | biomass | 38 | % | 25 | 9 | ||||||||
Coal | |||||||||||||||
American Bituminous1 | West Virginia | MPC | waste coal | 50 | % | 80 | 40 | ||||||||
CONTRACTED POWER PLANTS – International | |||||||||||||||
Doga | Republic of Turkey | TEDAS | natural gas | 80 | % | 180 | 144 | ||||||||
Total | 11,504 | 10,379 | |||||||||||||
1 | Plant is operated under contract by an EME operations and maintenance subsidiary or the plant is operated or managed directly by an EME subsidiary. |
13
2 | Electric purchaser abbreviations are as follows: |
APSC | Arizona Public Service Company | NPPD | Nebraska Public Power District | |||
CBPC | Corn Belt Power Cooperative | NSPC | Northern States Power Company | |||
CDWR | California Department of Water Resources | OGEC | Oklahoma Gas and Electric Company | |||
CECG | Constellation Energy Commodities Group, Inc. | PC | PacifiCorp | |||
CSA | City of San Antonio | PG&E | Pacific Gas & Electric Company | |||
ERCOT | Electric Reliability Council of Texas | PJM | PJM Interconnection, LLC | |||
IPLC | Interstate Power and Light Company | PSCO | Public Service Company of Oklahoma | |||
LIPA | Long Island Power Authority | SCE | Southern California Edison Company | |||
MDGS | Maryland Department of General Services | SPS | Southwestern Public Service | |||
MEC | Mid-American Energy Company | TEDAS | Türkiye Elektrik Dagitim Anonim Sirketi | |||
MPC | Monongahela Power Company | USM | University System of Maryland | |||
MRES | Missouri River Energy Services | WFEC | Western Farmers Electric Cooperative | |||
3 | Represents EME's current ownership interest. If the project achieves a specified rate of return, EME's interest will decrease. |
4 | Composed of six individual wind projects. |
5 | Two-thirds of project achieved commercial operation in December 2011. The remaining one-third of project achieved commercial operation in January 2012. |
Significant Customers
For information on EMG's significant customers, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 6. Derivative Instruments and Hedging Activities."
Asset Management and Trading Activities
EMG's power marketing and trading subsidiary, EMMT, manages the energy and capacity of EMG's merchant generating plants and, in addition, trades electric power, gas, oil and related commodity and financial products, including forwards, futures, options and swaps. EMMT segregates its activities into two categories:
• | Asset Management–EMMT engages in the sale of energy and capacity and the purchase and sale of fuels, including natural gas and fuel oil, through intercompany contracts with EMG's subsidiaries that own or lease EMG's facilities. EMG uses derivative instruments to reduce its exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, and transmission rights. The objective of these activities is to sell the output of EMG's facilities on a forward basis or to hedge the risk of future changes in prices or price differences between different locations. Hedging activities include on-peak and off-peak periods and may include load service requirements contracts with local utilities. Transactions related to hedging activities are designated separately from EMMT's trading activities. Not all contracts entered into by EMMT for hedging purposes qualify as hedges for accounting purposes. |
• | Trading–EMMT seeks to generate trading profits from volatility in the price of electricity, capacity, fuels, and transmission congestion by buying and selling contracts in wholesale markets under limitations approved by EMG's risk management committee. |
14
Energy and Infrastructure Investments
EMG's energy and infrastructure investments include leveraged leases and affordable housing projects in the United States. As of December 31, 2011, Edison Capital was the lessor with an investment balance (including current lease receivable) of $117 million in the following leveraged leases:
Transaction | Asset | Location | Basic Lease Term Ends | Investment Balance (In millions) | ||||||||
Vidalia: selling power to Entergy Louisiana, City of Vidalia | 192 MW hydro power plant | Vidalia, Louisiana | 2020 | $ | 69 | |||||||
Beaver Valley: selling power to Ohio Edison Company, Centerior Energy Corporation | 836 MW nuclear power plant | Shippingport, Pennsylvania | 2017 | $ | 46 | |||||||
American Airlines | 3 Boeing 767 ER aircraft | Domestic and international routes | 2016 | $ | 8 | 1 | ||||||
1 | American Airlines filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code in November 2011. As a result, Edison Capital recorded a pre-tax $26 million charge related it its net investments in aircraft leases. |
Seasonality
Due to fluctuations in electric demand resulting from warm weather during the summer months and cold weather during the winter months, electric revenues from the coal plants normally vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall), further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, income from the coal plants is seasonal and has significant variability from quarter to quarter. Seasonal fluctuations may also be affected by changes in market prices. For further discussion regarding market prices, see "EMG: Market Risk Exposures—Commodity Price Risk—Energy Price Risk" in the MD&A.
EMG's third quarter equity in income from its unconsolidated energy projects is normally higher than equity in income related to other quarters of the year due to seasonal fluctuations and higher energy contract prices during the summer months.
15
ENVIRONMENTAL REGULATION OF EDISON INTERNATIONAL AND SUBSIDIARIES
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 EMG's facilities, 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.
Edison International continues to monitor legislative and regulatory developments and to evaluate possible strategies for compliance with environmental regulations. Additional information about environmental matters affecting Edison International, including projected environmental capital expenditures, is included in the MD&A under the heading "SCE: Liquidity—Capital Investment Plan," "Item 8. Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies" and "—Note 10. Environmental Developments, and "Edison International (Consolidated): Liquidity and Capital Resources—Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets" in the MD&A.
Air Quality
The CAA, which regulates air pollutants from mobile and stationary sources, has a significant impact on the operation of fossil fuel plants, especially coal-fired plants. The CAA requires the US EPA to establish concentration levels in the ambient air for six criteria pollutants 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 SO2.
Federal environmental regulations of these criteria pollutants require states to adopt state implementation plans, known as SIPs, for certain pollutants, which detail how the state will attain the standards that are mandated by the relevant law or regulation. The SIPs must be equal to or more stringent than the federal requirements and must be submitted to the US EPA for approval. 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. If the attainment status of areas changes, states may be required to develop new SIPs that address the changes. Many of EMG's facilities are located in areas that have not attained NAAQS for ozone (affected by NOx emissions from power plants) and fine particulate matter (affected by SO2 and NOx emissions from power plants) and much of Southern California is in a non-attainment area for several criteria pollutants.
As described further below, on December 11, 2006, Midwest Generation entered into an agreement with the Illinois EPA, which was subsequently embodied in an Illinois rule called the Combined Pollutant Standard or "CPS," to reduce mercury, NOx and SO2 emissions at the Midwest Generation plants. The CPS 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 the CPS.
Nitrogen Oxide and Sulfur Dioxide
Clean Air Interstate and Cross-State Air Pollution Rules
The CAIR, issued by the US EPA on March 10, 2005, mandated significant reductions in NOx and SO2 emission allowance caps under the CAA in 28 eastern states and the District of Columbia. In 2008, the U.S. Court of Appeals for the D.C. Circuit initially vacated the CAIR, but later remanded the CAIR to the US EPA for the issuance of a revised rule. The CAIR remains in effect until a replacement regulation becomes effective.
On July 6, 2011, the US EPA adopted the Cross-State Air Pollution Rule ("CSAPR"). CSAPR establishes emissions reductions for annual SO2 emissions and annual and ozone season NOx emissions in two phases: a first phase originally scheduled to be effective January 1, 2012 and, in most states subject to the program (including Illinois and Pennsylvania), a second phase effective January 1, 2014 that requires additional reductions in annual SO2 emissions.
In December 2011, the United States Court of Appeals for the District of Columbia granted a stay of CSAPR pending completion of its review of the rule's validity. Oral argument is scheduled for April 13, 2012, and a court decision is expected during the third quarter of 2012. The court directed the US EPA to continue administering the CAIR until its review is completed.
16
CSAPR, like the CAIR, is an allowance-based regulation that provides for emissions trading. If the stay is lifted and CSAPR becomes effective, the amount of actual SO2 or NOx emissions from plant operations will need to be matched by a sufficient amount of SO2 or NOx allowances that are either allocated or purchased in the open market. In connection with CSAPR, the US EPA has, for each phase, established SO2 and NOx allowance allocations for each state and each generating unit subject to the regulation, and at the close of the annual or seasonal compliance period, units will need to surrender allowances for each ton of SO2 and NOx emitted or face penalties.
With the staying of CSAPR, CAIR SO2 allowances have been provided and a sufficient supply is available for purchase to permit Homer City to continue operations consistent with 2011 levels. If the stay is lifted, the SO2 allowances allocated to Homer City in CSAPR Phase I (25,797 tons in 2012 and 2013) would be significantly lower than the amount that would be required based on Homer City's historical emissions. It is unclear at this time whether Homer City would be able to acquire allowances in sufficient quantity to cover its normal operations during Phase I of CSAPR and whether it would be able to pass through the cost of such allowances in the marketplace. Accordingly, despite the stay, Homer City continues to evaluate alternative options, including reduced dispatch and fuel modifications, for complying with Phase I of CSAPR. The cost of allowances, together with possible operational impacts or reductions of output that may be required to comply with Phase I of CSAPR, could have a material effect on Homer City.
Homer City has begun work on designing SO2 and particulate emissions control equipment for Units 1 and 2. Based on preliminary estimates, Homer City expects the cost of such equipment to be approximately $700 million to $750 million. However, construction of these improvements is dependent upon funding from the owner-lessors or other third parties. For additional information, see "Edison International Overview—Management Overview of EMG—Homer City Lease."
Revised NAAQS for Sulfur Dioxide
In June 2010, the US EPA finalized the primary NAAQS for SO2 by establishing a new one-hour standard at a level of 75 parts per billion. In June 2011, Pennsylvania and Illinois submitted their initial recommended attainment/nonattainment designations in connection with the standard. Pennsylvania recommended designating Indiana County, where the Homer City plant is located, as nonattainment for the SO2 NAAQS. Illinois recommended designating parts of Tazewell County (where the Powerton plant is located) and Will and Cook Counties as nonattainment with this standard. The recommended designation for parts of Will and Cook Counties included the area where the Will County plant is located, but not the areas where Midwest Generation's other plants in those counties are located.
Illinois
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 the CPS. All of Midwest Generation's Illinois coal-fired electric generating units are subject to the CPS. The CPS also specifies the control technologies that are to be installed on some units by specified dates. Midwest Generation must either install the required technology by the specified deadline or shut down the unit. The principal emission standards and control technology requirements for NOx and SO2 under the CPS are as described below:
NOx Emissions–Beginning 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. Midwest Generation substantially completed installation of SNCR equipment in 2011 for compliance with the emission limitations. Capital expenditures relating to these controls were $105 million.
SO2 Emissions–Midwest 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.
Testing of dry scrubbing using Trona on select Midwest Generation units has demonstrated significant reductions in SO2 emissions. Use of dry sorbent injection technology in conjunction with low sulfur coal is expected to require substantially less capital and time to construct than the use of spray dryer absorber technology, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants, depending on competitors' costs. For further discussion, see "Edison International Overview—Management Overview of EMG—Midwest Generation and Compliance Plans and Cost" in the MD&A.
Pennsylvania
The Homer City plant was subject to the federal CAIR during 2011 and complied with both the NOx and SO2 requirements by using existing equipment and purchasing SO2 allowances. Pennsylvania adopted a state version of the CAIR, which the US EPA approved in December 2009. Homer City expects to comply with the Pennsylvania CAIR, which is substantially
17
similar to the federal CAIR as it existed prior to the implementation of CSAPR, in the same manner in which it complies with the federal standards.
Mercury/Hazardous Air Pollutants
Mercury and Air Toxics Standards Rule
In December 2011, the US EPA announced the Mercury and Toxics Air Standards ("MATS") rule, limiting emissions of hazardous air pollutants from coal- and oil-fired electrical generating units. The rule was published in the Federal Register on February 16, 2012, and becomes effective on April 16, 2012. EMG does not expect that these standards will require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. EMG also does not expect that these standards will require Homer City to make additional capital expenditures beyond those that would be required for compliance with CSAPR Phase II.
Illinois
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 will be included in calendar year 2016). Midwest Generation will 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.
Pennsylvania
Pennsylvania currently has no state level mercury regulations.
Ozone
National Ambient Air Quality Standards
In January 2010, the US EPA proposed a revision to the primary and secondary NAAQS for 8-hour ozone that it had finalized in 2008. The 8-hour ozone standard established in 2008 was 0.075 parts per million. In January 2010, the US EPA proposed establishing a primary 8-hour ozone NAAQS between 0.060 and 0.070 parts per million and a distinct secondary standard to protect sensitive vegetation and ecosystems. In September 2011, President Obama announced that the proposed revision was being withdrawn. The ozone NAAQS established in 2008 remains in place, but the implementation process must be completed before the 0.075 parts-per-million standard can be enforced. The US EPA has indicated that it intends to issue initial area designations of attainment, nonattainment, and unclassifiable areas across the nation in 2012. States will then be required to develop and submit SIPs outlining how compliance with the 2008 NAAQS will be achieved. New primary and secondary ozone standards are expected in 2014.
In January 2012, the US EPA indicated that it intended to designate the counties in Illinois where Midwest Generation's coal-fired power plants are located as nonattainment with the 2008 NAAQS. In December 2011, the US EPA indicated that it intended to designate Indiana County, where the Homer City plant is located, as in attainment with the 2008 NAAQS.
Regional Haze
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.
In relation to Four Corners, the US EPA issued its proposed FIP in October 2010. The proposed FIP would require the installation of SCR pollution control equipment within designated time periods. In November 2010, SCE and APS entered into an agreement for the sale of SCE's interest in Four Corners Units 4 and 5 to APS, subject to regulatory approvals and other conditions. Due to the investment constraints of SB 1368, the California law on GHG emission performance standards discussed below in "—Greenhouse Gas Regulation—Regional Initiatives and State Legislation," SCE does not expect to be a Four Corners participant after the 2016 expiration of the current participant agreements and does not expect to participate in any investment in Four Corners SCRs. See "Item 8. Edison International Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment" for more information on the sale of SCE's interest in Four Corners.
18
Illinois and Pennsylvania
Both Pennsylvania and Illinois have submitted their proposed SIP revisions to the US EPA to address regional haze. Illinois proposed that the emission reductions that the Midwest Generation plants will be required to make pursuant to the CPS, discussed above in "—Nitrogen Oxide and Sulfur Dioxide—Illinois," satisfy the BART requirement. Pennsylvania proposed that the existing particulate matter emission limits on the Homer City plant, as well as the plant's participation in the CAIR, would satisfy the BART requirement in that state. Because the CAIR was scheduled to expire on December 31, 2011, the US EPA proposed, on December 30, 2011, a limited disapproval of Pennsylvania's SIP, as well as a Federal Implementation Plan that would allow the Homer City plant's participation in CSAPR to satisfy the BART requirement. It is unclear how the stay of CSAPR will affect the Pennsylvania SIP. EME believes that the control measures being undertaken to comply with other environmental regulations will likely satisfy the requirements of these SIPs.
New Source Review Requirements
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 NSR compliance issues at the nation's coal-fired power plants. The US EPA has filed enforcement actions against Homer City and Midwest Generation alleging NSR violations. For further discussion, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
New Mexico
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, including information about Four Corners' capital projects from 1990 to the present. SCE understands that in other cases the US EPA has utilized responses to similar Section 114 letters to examine whether power plants have triggered NSR requirements under the CAA. In October 2011, four environmental organizations filed a lawsuit against the Four Corners owners alleging NSR violations. See "Item 8. Edison International Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment," for information on the sale of SCE's interest in Four Corners.
Water Quality
Clean Water Act
Regulations under the federal Clean Water Act govern critical operating parameters at generating facilities, such as the temperature of effluent discharges and the location, design and construction of cooling water intake structures at generating facilities. In March 2011, the US EPA proposed standards under the federal Clean Water Act that would affect cooling water intake structures at generating facilities. The standards are intended to protect aquatic organisms by reducing capture in screens attached to cooling water intake structures (impingement) and in the water volume brought into the facilities (entrainment). The regulations are expected to be finalized by July 2012. The required measures to comply with the proposed standards regarding entrainment are subject to the discretion of the permitting authority, and Edison International is unable at this time to assess potential costs of compliance, which could be significant for the Midwest Generation plants and San Onofre, but are not expected to be material for the Homer City plant, which already has cooling towers.
California—Prohibition on the Use of Ocean-Based Once-Through Cooling
California has a US EPA-approved program to issue individual or group permits for the regulation of Clean Water Act discharges. California also regulates certain discharges not regulated by the US EPA. Effective October 1, 2010, the California State Water Resources Control Board issued a final policy, which establishes closed-cycle wet cooling as required technology for retrofitting existing once-through cooled plants like SCE's San Onofre and many of the existing fossil-fueled power plants along the California coast. The final policy required an independent engineering study to be completed prior to the fourth quarter of 2013 regarding the feasibility of compliance by California's two coastal nuclear power plants. The policy may result in significant capital expenditures at San Onofre and may affect its operations.
Illinois
Midwest Generation is a party to an administrative proceeding before the Illinois Pollution Control Board to determine whether more stringent thermal and effluent water quality standards for the Chicago Area Waterway System and Lower Des Plaines River, which supply cooling water to Midwest Generation's Will County and Joliet Stations, will be implemented. The rule, if implemented, is expected to affect the manner in which those stations use water for station cooling. 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.
19
Coal Combustion Wastes
US EPA regulations currently classify coal ash and other coal combustion residuals as solid wastes that are exempt from hazardous waste requirements. This classification enables beneficial uses of coal combustion residuals, such as for cement production and fill materials. Midwest Generation currently provides a portion of its coal combustion residuals for beneficial uses. In June 2010, the US EPA published proposed regulations relating to coal combustion residuals that could result in their reclassification. For further discussion see "Item 8. Edison International Notes to Consolidated Financial Statements— Note 10. Environmental Developments."
Greenhouse Gas Regulation
There have been a number of federal and state legislative and regulatory initiatives to reduce GHG emissions. Any climate change regulation or other legal obligation that would require substantial reductions in GHG emissions or that would impose additional costs or charges for the emission of GHGs could significantly increase the cost of generating electricity from fossil fuels, and especially from coal-fired plants, as well as the cost of purchased power, which could adversely affect Edison International.
Federal Legislative/Regulatory Developments
In June 2010, the US EPA issued the Prevention of Significant Deterioration ("PSD") and Title V Greenhouse Gas Tailoring Rule, known as the "GHG tailoring rule." This regulation generally subjects newly constructed sources of GHG emissions and newly modified existing major sources to the PSD air permitting program beginning in January 2011 (and later, to the Title V permitting program under the CAA); however the GHG tailoring rule significantly increases the emissions thresholds that apply before facilities are subjected to these programs. The emissions thresholds for CO2 equivalents in the final rule vary from 75,000 tons per year to 100,000 tons per year depending on the date and whether the sources are new or modified.
Regulation of GHG emissions pursuant to the PSD program could affect efforts to modify EMG's or SCE's facilities in the future, and could subject new capital projects to additional permitting or emissions control requirements that could delay such projects. In December 2010, the US EPA announced that it had entered into a settlement with various states and environmental groups to resolve a long-standing dispute over regulation of GHGs from electrical generating units pursuant to the New Source Performance Standards in the CAA and would propose performance standards for emissions from new and modified power plants and emissions guidelines for existing power plants. The specific requirements will not be known until the regulations are finalized. Since January 2010, the US EPA's Final Mandatory GHG Reporting Rule has required all sources within specified categories, including electric generation facilities, to monitor emissions and to submit annual reports to the US EPA by March 31 of each year. EMG's 2011 GHG emissions were approximately 43 million metric tons. SCE's 2011 GHG emissions were approximately 5.8 million metric tons.
Regional Initiatives and State Legislation
Regional initiatives and state legislation may also require reductions of GHG emissions and it is not yet clear whether or to what extent any federal legislation would preempt them. If state and/or regional initiatives remain in effect after federal legislation is enacted, utilities and generators could be required to satisfy them in addition to the federal standards.
Edison International subsidiary operations in California are subject to two laws governing GHG emissions. The first law, the California Global Warming Solutions Act of 2006 (also referred to as AB 32), establishes a comprehensive program to reduce GHG emissions. AB 32 requires the California Air Resources Board ("CARB") to develop regulations, effective in 2012, that would reduce California's GHG emissions to 1990 levels in yearly increments by 2020. In December 2011, the CARB regulation was officially published establishing a California cap-and-trade program. The first compliance period under the regulations is for 2013 GHG emissions. CARB regulations implementing a cap-and-trade program and the cap-and-trade program itself, continue to be the subject of litigation. In December 2011, a federal district court enjoined the Low Carbon Fuel Standard, another AB 32 program regulating the carbon content of transportation fuels, on constitutional commerce clause grounds. Additional litigation challenging the cap-and-trade program on similar grounds is expected, though no suit has been filed to date.
The second law, SB 1368, required the CPUC and the CEC to adopt GHG emission performance standards restricting the ability of California investor-owned and publicly owned utilities, respectively, to enter into long-term arrangements for the purchase of electricity. The standards that have been adopted prohibit these entities, including SCE, from entering into long-term financial commitments with generators that emit more than 1,100 pounds of CO2 per MWh, the performance of a combined-cycle gas turbine generator. SB 1368 may prohibit SCE from making emission control expenditures at Four Corners. See "Item 8. Edison International Notes to Consolidated Financial Statements—Note 2. Property, Plant and Equipment" for information on the sale of SCE's interest in Four Corners.
20
California law has also required SCE to increase its 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 provided from such resources (the "RPS Program") by no later than December 31, 2010 or such later date as flexible compliance requirements permit. In accordance with the procurement rules and regulations, SCE demonstrated full compliance with the RPS Program in its March 2011 and August 2011 filings.
In April 2011, California enacted a law requiring California retail sellers of electricity to procure 33% of their customers' electricity requirements from renewable resources, as defined in the statute. The impact of the new 33% law will depend on how the CPUC and CEC implement the law, which remains uncertain. On December 1, 2011, the CPUC approved a decision setting procurement quantity requirements for CPUC-regulated retail sellers that incrementally increase to 33% over several periods between January 2011 and December 31, 2020. The quantity would remain at 33% of retail sales for each year thereafter. Currently SCE estimates its delivery of eligible renewable resources to customers to be 21% of its total energy portfolio for 2011.
Litigation Developments
Litigation alleging that GHG is a public and private nuisance may affect Edison International and its subsidiaries, whether or not they are named as defendants. The law is unsettled on whether this litigation presents questions capable of judicial resolution or political questions that should be resolved by the legislative or executive branches. For further discussion, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 10. Environmental Developments."
ITEM 1A. RISK FACTORS
RISKS RELATING TO EDISON INTERNATIONAL
Edison International's subsidiaries are 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 NRC 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. 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. The process of obtaining licenses and permits from regulatory authorities may be delayed or defeated by concerted community opposition and such delay or defeat would have an adverse effect on SCE's business.
EMG'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. 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. EMG in the course of its business must obtain and periodically renew licenses, permits and approvals for its facilities. 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. 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. EMG is required to surrender emission allowances equal to emissions of specific substances in connection with the operation of its facilities. This may require the purchase of allowances, which are subject to price volatility and which could be unavailable.
This extensive governmental regulation creates significant risks and uncertainties for Edison International's business. Existing regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to SCE, EMG or their facilities or operations in a manner that may have a detrimental effect on Edison International's business or result in significant additional costs. In addition, regulation adopted via the public initiative process may apply to SCE or EMG, or its facilities or operations in a manner that may have a detrimental effect on Edison International's business or result in significant additional costs.
21
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 and frequently changing environmental regulations and permitting requirements that involve significant and increasing costs and substantial uncertainty. SCE and EMG devote significant resources to environmental monitoring, emissions control equipment, mitigation projects, 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 adoption of laws and regulations to implement greenhouse gas controls could adversely affect operations, particularly of the coal-fired plants. Other environmental laws, particularly with respect to air emissions, disposal of ash, wastewater discharge, and cooling water systems, are also generally becoming more stringent. The continued operation of SCE and EMG facilities, particularly the coal-fired facilities, is expected to require substantial capital expenditures for environmental controls or cessation of operations. Cessation of operations of such coal-fired plants at EMG would have a material adverse effect on EMG. SCE and EMG may also be exposed to risks arising from past, current or future contamination at its former or existing facilities or with respect to offsite waste disposal sites that have been used in its operations. Current and future state laws and regulations in California also could increase the required amount of power that must be procured from renewable resources. For further discussion of the environmental regulations applicable to Edison International and its subsidiaries, see "Item 1. Business—Environmental Regulation of Edison International and Subsidiaries" and "Item 8. SCE Notes to Consolidated Financial Statements—Note 10. Environmental Developments."
Edison International's liquidity depends on SCE's ability to pay dividends to Edison International and its subsidiaries' payment of tax-allocation payments that may become due 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 SCE and its ability to make upstream distributions. Prior to paying dividends to Edison International, SCE has financial and regulatory obligations that must be satisfied, including, among others, debt service and preferred stock dividends. SCE and EMG may also owe tax-allocation payments to Edison International under applicable tax-allocation or payment agreements. 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.
The businesses of Edison International's subsidiaries may be adversely affected by technological developments.
Technological advancements such as energy storage or self generation via solar panels may adversely affect the economics of SCE's business as a regulated utility. Other technological advancements in the area of power production that create or increase the supply of less expensive power, such as shale natural gas extraction technology, may adversely affect EMG's business as an independent merchant power producer. See "Risks Relating to SCE" and "Risks Relating to EMG" below for further discussion.
The generation, transmission and distribution of electricity are dangerous and involve inherent risks of injury to employees and the general public.
Electricity is dangerous for employees and the general public should they come in contact with power lines or electrical equipment. Injuries caused by such contact can subject SCE and EMG to liability that, despite the existence of insurance coverage, can be significant. In the wake of recent natural disasters such as windstorms, which can cause wildfires, pole failures and associated property damage and outages, the CPUC has increased its focus on public safety issues with an emphasis on heightened compliance with construction and operating standards and the potential for penalties being imposed on utilities. Such penalties and liabilities could be significant but are very difficult to predict. The range of possible penalties and liabilities includes amounts that could adversely affect SCE's and EMG's liquidity and results of operations.
RISKS RELATING TO SCE
Regulatory Risks
SCE's financial results depend upon its ability to recover its costs in a timely manner from its customers through regulated rates.
SCE's ongoing financial results depend 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 FERC. SCE's financial results also depend on its ability to earn a reasonable return on capital, including long-term debt and equity. SCE's capital investment plan, increasing procurement of renewable power, increasing environmental regulations,
22
moderating demand, and the cumulative impact of other public policy requirements, collectively place continuing upward pressure on customer rates. Increases in self generation also reduce the pool of customers from whom fixed costs are recovered, while costs potentially increase due to system modifications that may be necessary to cope with the systemic effects of self-generation. Customers that self-generate their own power do not currently pay most transmission and distribution charges and are only subject to certain non-bypassable charges. The net result is to increase utility rates further for those customers who do not self-generate, which encourages more self generation and further rate increases. If SCE is unable to obtain a sufficient rate increase or 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. For further information on SCE's rate requests, see "Edison International Overview—Management Overview of SCE—2012 General Rate Case" and "—FERC Formula Rates" in the MD&A.
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, environmental credits 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 primarily resulting from changes to commodity prices. In addition, SCE is subject to the risks of unfavorable or untimely CPUC decisions about the compliance with SCE's procurement plan and the reasonableness of certain procurement-related costs.
SCE may not be able to hedge its risk for commodities on economic 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 operations. See "SCE: Liquidity and Capital Resources—Market Risk Exposures" in the MD&A.
Operating Risks
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's infrastructure is aging and could pose a risk to system reliability. In order to mitigate this risk, SCE is engaged in one of the largest infrastructure investment programs in its history, which involves multiple large-scale projects in multiple locations. This substantial increase in activity from SCE's historical levels elevates the operational risks and the need for superior execution in its activities. SCE's financial condition and results of operations could be materially affected if it is unable to successfully manage these risks as well as the risks inherent in operating and improving its facilities, the operation of which can be hazardous. SCE's inherent operating risks include such matters as the risks of human performance, workforce capabilities, public opposition to infrastructure projects, delays, environmental mitigation costs, difficulty in estimating costs, system limitations and degradation, and interruptions in necessary supplies. For example, SCE has recently experienced significant additional costs and disruptions in the progress of its Tehachapi Renewable Transmission Project. See "SCE: Liquidity and Capital Resources—Capital Investment Plan" in the MD&A.
SCE's systems and network infrastructure may be vulnerable to cyber attacks, intrusions or other catastrophic events that could result in their failure or reduced functionality.
Regulators, such as the NERC, and U.S. Government Departments, including the Departments of Defense, Homeland Security and Energy, have noted that the U.S. national electric grid and other energy infrastructures have potential vulnerabilities to cyber attacks and disruptions and that such cyber threats are becoming increasingly sophisticated and dynamic. SCE's operations require the continuous operation of critical information technology systems and network infrastructure. Although SCE actively monitors developments in this area and is involved in various industry groups and government initiatives, no security measures can completely shield such systems and infrastructure from vulnerabilities to cyber attacks, intrusions or other catastrophic events that could result in their failure or reduced functionality. If SCE's information technology systems security measures were to be breached or a critical system failure were to occur without timely recovery, SCE could be unable to fulfill critical business functions and/or sensitive confidential personal and other data could be compromised, which could adversely affect SCE's financial condition and results of operations. See "Item 1. Business—Southern California Edison Company—Regulation—NERC" for further discussion.
There are inherent risks associated with operating nuclear power generating facilities.
Continued NRC scrutiny of San Onofre may result in additional corrective actions that will increase operations and maintenance costs or require additional capital expenditures.
23
San Onofre is subject to extensive oversight and scrutiny of the NRC. This scrutiny may result in SCE being required to take additional corrective actions and incur increased operations and maintenance expenses or new capital expenditures. If SCE is unable to take effective corrective actions required by the NRC, the NRC has the authority to impose fines or shut down a unit, or both, depending upon the NRC's assessment of the severity of the situation, until compliance is achieved. See "Item 1. Business—Southern California Edison Company—Regulation—Nuclear Power Plant Regulation" for further discussion.
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 nuclear incident liability claims were to exceed $375 million, the remaining amount would be made up from contributions of approximately $12.2 billion made by all of the nuclear facility owners in the U.S., up to an aggregate total of $12.6 billion. There is no assurance that the CPUC would allow SCE to recover the required contribution made in the case of one or more nuclear incident claims that exceeded $375 million. If this public liability limit of $12.6 billion is insufficient, federal law contemplates that additional funds may be appropriated by Congress. There can be no assurance of SCE's ability to recover uninsured costs in the event the additional federal appropriations are insufficient. See "Item 8. Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Nuclear Insurance."
Spent fuel storage capacity could be insufficient to permit long-term operation of SCE's nuclear plants.
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.
SCE's insurance coverage for wildfires arising from its ordinary operations may not be sufficient and Edison International may not be able to obtain sufficient insurance on SCE's behalf for such occurrences.
Edison International has been experiencing increased costs and difficulties in obtaining insurance coverage for wildfires that could arise from SCE's ordinary operations. In addition, the insurance Edison International has obtained on SCE's behalf for wildfire liabilities may not be sufficient. Uninsured losses and increases in the cost of insurance may not be recoverable in customer rates. A loss which is not fully insured or cannot be recovered in customer rates could materially and adversely affect Edison International's and SCE's financial condition and results of operations. Furthermore, insurance for wildfire liabilities may not continue to be available at all or at rates or on terms similar to those presently available to Edison International. See "Item 8. Edison International Notes to Consolidated Financial Statements—Note 10. Environmental Developments."
Financing Risks
As a capital intensive company, SCE relies on access to the capital markets. If SCE were unable to access the capital markets or the cost of financing were to substantially increase, its liquidity and operations would be adversely affected.
SCE regularly accesses the capital markets to finance its activities and is expected to do so by its regulators as part of its obligation to serve as a regulated utility. SCE's needs for capital for its ongoing infrastructure investment program are substantial. SCE's ability to arrange financing as well as its ability to refinance debt and make scheduled payments of principal and interest 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. SCE's failure to obtain additional capital from time to time would have a material adverse effect on SCE's liquidity and operations. See "SCE: Liquidity and Capital Resources—Capital Investment Plan" and "—Historical Segment Cash Flows" in the MD&A.
RISKS RELATING TO EMG
Liquidity Risks
EME and its subsidiaries have significant cash requirements, limited sources of capital and expect to incur substantial losses in 2012 and subsequent years.
At December 31, 2011, EME had corporate cash and cash equivalents of $951 million and $498 million of available
24
borrowing capacity under its $564 million revolving credit facility maturing in June 2012 and Midwest Generation had cash and cash equivalents of $213 million and $497 million of available borrowing capacity under its $500 million credit facility maturing in June 2012. Subsequent to the end of the fiscal year, EME terminated its revolving credit facility and there can be no assurance that Midwest Generation will be eligible to draw on its credit facility prior to maturity. Any replacements of these credit lines will likely be on less favorable terms and conditions, and there is no assurance that EME will, or will be able to, replace these credit lines or any portion of them.
As of December 31, 2011, EME's consolidated debt was approximately $4.9 billion, of which $1.2 billion was nonrecourse project debt of EME's subsidiaries and the balance was senior unsecured debt of EME. In addition, EME's subsidiaries had $2.6 billion of long-term, power plant lease obligations that are due over a period ranging up to 23 years. Compliance with current and forthcoming environmental requirements will add to EME's near-term liquidity needs.
Unless energy and capacity prices increase, EME expects that it will experience further losses and reductions in cash flow in 2012 and subsequent years. EME's liquidity will be strained by a continuation of recent adverse trends combined with pending debt maturities, higher operating costs and the need to retrofit its coal-fired plants to comply with governmental regulations. EME's and Midwest Generation's deteriorating financial results and below-investment grade credit status may limit their ability to extend or replace credit facilities, including those maturing in 2012, should they choose to do so, and the terms and conditions of any refinancing could be substantially less favorable than those in previous credit facilities, depending on market conditions. In the case of a further downgrade, EME expects that these negative effects would become more pronounced. If cash flow and other means for assuring liquidity are unavailable or insufficient, EME may be unable to complete environmental improvements at its coal plants (which in turn could lead to unit shutdowns) or to pay its senior debt as it matures. If EME's credit facilities are not replaced, EME's ability to hedge its merchant coal exposure or carry out its trading activities may also be limited. The terms of EME's and its subsidiaries' debt instruments may restrict EME's ability to sell assets or incur secured indebtedness, and EME's subsidiaries' debt instruments may limit EME's ability to seek additional capital, or restructure or refinance debt to satisfy liquidity needs. For further discussion, see "EMG: Liquidity and Capital Resources" in the MD&A.
EME receives tax-allocation payments from Edison International only if, and only to the extent that, EME is included in the consolidated tax returns of Edison International and Edison International is able to utilize tax losses and credits generated by EME. EME may be required to make tax-allocation payments to Edison International.
EME's right to receive tax-allocation payments and the amount of and timing of those payments are dependent on the inclusion of EME in the consolidated income tax returns of Edison International and other factors, including the amount of consolidated taxable income and net operating losses of Edison International, and other tax items of EME, its subsidiaries, and other subsidiaries of Edison International. Edison International has not been able to fully utilize EME's consolidated tax losses and credits as a result of accelerated tax deductions taken by the consolidated group under the Small Business Jobs Act of 2010 and the 2010 Tax Relief Act and SCE's priority over EME in the utilization of available tax benefits. Realization of EME's tax losses and tax credits is not expected to begin again until at least 2013, subject to future changes in tax laws and Edison International's taxable income, and it may take several years before such benefits can be fully utilized. As of December 31, 2011, EME had recorded deferred tax assets of $520 million related to loss carryforwards and unused credits. EME expects to make tax-allocation payments to Edison International during 2012 of approximately $185 million as a result of the reallocation of tax obligations from an expected Edison International consolidated net operating loss in 2011.
These arrangements are subject to the terms of the tax-allocation and payment agreements among Edison International, EME and other Edison International subsidiaries. The agreements under which EME makes and receives tax-allocation payments may be terminated by the immediate parent company at any time, by notice given before the first day of the first year with respect to which the termination is to be effective. However, termination does not relieve any party of any obligations with respect to any tax year beginning prior to the notice. See "EMG: Liquidity and Capital Resources—Intercompany Tax-Allocation Agreement" in the MD&A.
Regulatory and Environmental Risks
The controls imposed on EMG's coal plants as a result of environmental regulations, including the Combined Pollutant Standard may require material expenditures or unit shutdowns.
Capital expenditures relating to required environmental controls for EMG's coal plants (including the CPS, to which all of Midwest Generation's coal-fired generating units are subject) are expected to be significant. In February 2012, EME decided to shut down the Fisk Station by the end of 2012 and the Crawford Station by the end of 2014 and concluded it was less likely to install environmental controls at the Waukegan Station and Joliet Unit 6. EME may ultimately decide to shut down the Waukegan Station and Joliet Unit 6, and possibly other units, rather than make improvements. Unit shutdowns could have
25
an adverse effect on EMG's business, results of operation and financial condition. For more information about EMG's plans for environmental compliance, see "Item 1. Business—Environmental Regulation of Edison International and Subsidiaries—Air Quality—Nitrogen Oxide and Sulfur Dioxide," "Edison International (Consolidated): Liquidity and Capital Resources—Critical Accounting Estimates and Policies" in the MD&A, and "Item 8. Edison International Notes to Consolidated Financial Statements—Note 10. Environmental Developments."
Market Risks
EMG has substantial interests in merchant energy power plants which are subject to market risks related to wholesale energy prices because they operate without long-term power purchase agreements. Wholesale energy prices have substantially declined in recent years.
EMG'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. 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 coal plants, EMG has concentrated exposure to market conditions and fluctuations in PJM. Prices for power and capacity have declined significantly due largely to lower natural gas prices and have been affected in recent years by increased use of demand response technology, changes in final demand for power during the economic slowdown, and technological developments that have increased access to natural gas shale reserves, resulting in substantial declines in market prices for natural gas which supplies power plants that compete with EMG's coal plants.
Market prices of energy, capacity and ancillary services sold from these power plants are influenced by multiple factors beyond EMG's control, and thus there is considerable uncertainty whether or when current depressed prices will recover. EMG'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. The effectiveness of EMG's hedging activities may depend on the amount of credit available to post collateral, either in support of performance guarantees or as cash margin, and liquidity requirements may be greater than EMG anticipates or will be able to meet. EMG cannot provide assurance that its hedging strategies will successfully mitigate market risks. For more detail on these matters, see "EMG: Market Risk Exposures—Commodity Price Risk" in the MD&A.
EMG's financial results can be affected by changes in prices, transportation cost, and supply interruptions related to fuel, sorbents, and other commodities used for power generation and emission controls.
In addition to volatile power prices, EMG's business is subject to changes in the cost of fuel, sorbents, and other commodities used for power generation and emission controls, and in the cost of transportation. These costs can be volatile and are influenced by many factors outside of EMG's control. The price at which EMG can sell its energy may not rise or fall at the same rate as a corresponding rise or fall in commodity costs. Operations at the coal plants are dependent upon the availability and affordability of coal which is available only from a limited number of suppliers and which, in the case of Midwest Generation, is transported by rail under a multi-year long-term transportation contract. All of these factors may have an adverse effect on EMG's financial condition and results of operations. See "EMG: Market Risk Exposures—Commodity Price Risk" in the MD&A.
Competition could adversely affect EMG's business
EMG 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, greater ability to withstand losses, larger staffs or more experience than EMG. 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 EMG's ability to compete effectively in the markets in which those entities operate. Newer plants owned by EMG's competitors are often more efficient than EMG's facilities and may also have lower costs of operation. Over time, some of EMG's merchant facilities may become obsolete in their markets, or be unable to compete with such plants.
Operating Risks
EMG's capital projects may not be successful.
EMG's capital projects are subject to risks including, without limitation, risks related to financing, construction, permitting,
26
and governmental approvals. EME may be required to spend significant amounts before it can determine whether a project is feasible or economically attractive. The timing of such projects may be delayed beyond the date that equipment is ready for installation, in which case EMG may be required to incur material equipment and/or material costs with no deployment plan at delivery. Due to competing capital needs, EMG's further development of its renewable business will depend upon the availability of third-party equity capital.
EMG's projects may be affected by general operating risks and hazards customary in the power generation industry. EMG may not have adequate insurance to cover all these hazards.
The operation of power generation facilities is a potentially dangerous activity that involves many operating risks, including transmission disruptions and constraints, equipment failures or shortages, and system limitations, degradation and interruption. EMG's operations are also subject to risks of human performance and workforce capabilities. There can be no assurance that EMG's insurance will be sufficient or effective under all circumstances or protect against all hazards to which EMG may be subject, or that insurance coverage will continue to be available on terms similar to those presently available, or at all. EMG has a number of older facilities that are subject to higher risks of failure or outage, and EMG has in the past experienced serial defects in certain models of wind turbines deployed at its wind projects.
Uncertainties in EMG's future operations could affect its ability to attract and retain skilled people.
Uncertainties concerning EMG's future operations could affect its ability to attract and retain qualified personnel with experience in the energy industry. If EMG is unable to successfully attract and retain an appropriately qualified workforce, its results of operations will be negatively affected.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2. PROPERTIES
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 "Item 1. Business—Southern California Edison Company—Properties." Properties of EMG are described above under "—Edison Mission Group Inc.—Properties."
ITEM 3. LEGAL PROCEEDINGS
Midwest Generation New Source Review and Other Litigation
Information about the Midwest Generation New Source Review and Other Litigation appears in "Item 8. Edison International Notes to the Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies."
Homer City New Source Review and Other Litigation
Information about the Homer City New Source Review and Other Litigation appears in "Item 8. Edison International Notes to the Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies."
27
Pursuant to Form 10-K's General Instruction G(3), the following information is included as an additional item in Part I:
EXECUTIVE OFFICERS OF THE REGISTRANT
Executive Officer | Age at December 31, 2011 | Company Position |
Theodore F. Craver, Jr. | 60 | Chairman of the Board, President and Chief Executive Officer, Edison International |
Robert L. Adler | 64 | Executive Vice President and General Counsel, Edison International |
Polly L. Gault | 58 | Executive Vice President, Public Affairs, Edison International |
W. James Scilacci | 56 | Executive Vice President, Chief Financial Officer and Treasurer, Edison International |
Janet T. Clayton | 57 | Senior Vice President, Corporate Communications, Edison International |
Daryl D. David | 57 | Senior Vice President, Human Resources, Edison International |
Bertrand A. Valdman | 49 | Senior Vice President, Strategic Planning |
Mark C. Clarke | 55 | Vice President and Controller, Edison International |
Ronald L. Litzinger | 52 | President, SCE |
Pedro J. Pizarro | 46 | President, EMG and EME |
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, David, and Valdman, and Ms. Clayton, 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:
28
Executive Officers | Company Position | Effective Dates | ||
Theodore F. Craver, Jr. | Chairman of the Board, President and Chief Executive Officer, Edison International President, Edison International Chairman of the Board, President and Chief Executive Officer, EMG Chairman of the Board, President and Chief Executive Officer, EME | August 2008 to present April 2008 to July 2008 November 2005 to March 2008 January 2005 to March 2008 | ||
Robert L. Adler | Executive Vice President and General Counsel, Edison International Executive Vice President, Edison International Partner, Munger, Tolles & Olson LLP1 | August 2008 to present July 2008 to August 2008 January 1978 to June 2008 | ||
Polly L. Gault | Executive Vice President, Public Affairs, Edison International Executive Vice President, Public Affairs, SCE Senior Vice President, Public Affairs, Edison International and SCE | March 2007 to present March 2007 to September 2008 March 2006 to February 2007 | ||
W. James Scilacci | Executive Vice President, Chief Financial Officer and Treasurer, Edison International Senior Vice President and Chief Financial Officer, EME Senior Vice President and Chief Financial Officer, EMG | August 2008 to present March 2005 to July 2008 November 2005 to July 2008 | ||
Janet T. Clayton | Senior Vice President, Corporate Communication, Edison International President, Think Cure2 Assistant Managing Editor, Los Angeles Times3 | April 2011 to present Jan 2008 to April 2011 June 2004 to September 2007 | ||
Daryl D. David | Senior Vice President, Human Resources, Edison International Executive Vice President & Chief Human Resources Officer, Washington Mutual, Inc.4 | June 2009 to present May 2000 to October 2008 | ||
Bertrand A. Valdman | Senior Vice President, Strategic Planning, Edison International Executive Vice President, Chief Operating Officer Puget Sound Energy5 Senior Vice President, Chief Financial Officer Puget Sound Energy5 | March 2011 to present May 2007 to March 2011 December 2003 to May 2007 | ||
Mark C. Clarke | Vice President and Controller, Edison International Vice President and Controller, EME | August 2009 to present January 2003 to July 2009 | ||
Ronald J. Litzinger | President, SCE Chairman of the Board, President and Chief Executive Officer, EMG and EME Senior Vice President, Transmission and Distribution, SCE | January 2011 to present April 2008 to December 2010 May 2005 to March 2008 | ||
Pedro J. Pizarro | President, EMG and EME Executive Vice President, Power Operations, SCE Senior Vice President, Power Procurement, SCE | January 2011 to present April 2008 to December 2010 May 2005 to March 2008 | ||
1 | Munger, Tolles & Olson LLP is a California-based law firm. Mr. Adler also served as a Co-Managing Partner. |
2 | Think Cure is a community-based nonprofit organization that raises funds to accelerate collaborate research to cure cancer and is not a parent, affiliate or subsidiary of Edison International. |
3 | The Los Angeles Times is a daily newspaper published in Los Angeles, California and is not a parent, affiliate or subsidiary at Edison International. |
4 | Washington Mutual was a bank holding company and the former owner of Washington Mutual Bank and is not a parent, subsidiary or affiliate of Edison International. |
5 | Puget Sound Energy is a regulated energy utility in Washington State and is not a parent, affiliate or subsidiary of Edison International. |
29
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.
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 Statements—Note 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 Parent and Other" and in "Item 8. Edison International Notes to Consolidated Financial Statements—Note 5. Debit and Credit Agreements." The number of common stockholders of record of Edison International was 45,430 on February 24, 2011. Additional information concerning the market for Edison International's Common Stock is set forth on the cover page of this report. The description of Edison International's equity compensation plans required by Item 201(d) of Regulation S-K is incorporated by reference to "Part III—Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters" of this report.
Issuer Purchases of Securities
The following table contains information about all purchases of Edison International Common Stock made by or on behalf of Edison International in the fourth quarter of 2011.
Period | (a) Total Number of Shares (or Units) Purchased1 | (b) Average Price Paid per Share (or Unit)1 | (c) Total Number of Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs | (d) Maximum Number (or Approximate Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs | ||||||
October 1, 2011 to October 31, 2011 | 499,480 | $ | 38.84 | — | — | |||||
November 1, 2011 to November 30, 2011 | 812,326 | $ | 39.46 | — | — | |||||
December 1, 2011 to December 31, 2011 | 446,349 | $ | 40.71 | — | — | |||||
Total | 1,758,155 | $ | 39.60 | — | — | |||||
1 | The shares were purchased by agents acting on Edison International's behalf for delivery to plan participants to fulfill requirements in connection with Edison International's: (i) 401(k) Savings Plan; (ii) Dividend Reinvestment and Direct Stock Purchase Plan; and (iii) long-term incentive compensation plans. The shares were purchased in open-market transactions pursuant to plan terms or participant elections. The shares were never registered in Edison International's name and none of the shares purchased were retired as a result of the transactions. |
30
Comparison of Five-Year Cumulative Total Return
At December 31, | |||||||||||||||||
2006 | 2007 | 2008 | 2009 | 2010 | 2011 | ||||||||||||
Edison International | $ | 100 | $ | 120 | $ | 74 | $ | 84 | $ | 96 | $ | 107 | |||||
S & P 500 Index | 100 | 105 | 66 | 84 | 97 | 99 | |||||||||||
Philadelphia Utility Index | 100 | 119 | 87 | 95 | 101 | 120 | |||||||||||
Note: Assumes $100 invested on December 31, 2006 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. |
31
ITEM 6. SELECTED FINANCIAL DATA
Selected Financial Data: 2007 – 2011
(in millions, except per-share amounts) | 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||
Edison International and Subsidiaries | |||||||||||||||||||
Operating revenue | $ | 12,760 | $ | 12,409 | $ | 12,361 | $ | 14,112 | $ | 12,868 | |||||||||
Operating expenses | $ | 12,440 | $ | 10,283 | $ | 10,963 | $ | 11,549 | $ | 10,359 | |||||||||
Income from continuing operations | $ | 24 | $ | 1,303 | $ | 952 | $ | 1,348 | $ | 1,307 | |||||||||
Net income | $ | 21 | $ | 1,307 | $ | 945 | $ | 1,348 | $ | 1,305 | |||||||||
Net income (loss) attributable to common shareholders | $ | (37 | ) | $ | 1,256 | $ | 849 | $ | 1,215 | $ | 1,098 | ||||||||
Weighted-average shares of common stock outstanding (in millions) | 326 | 326 | 326 | 326 | 326 | ||||||||||||||
Basic earnings (loss) per share: | |||||||||||||||||||
Continuing operations | $ | (0.10 | ) | $ | 3.83 | $ | 2.61 | $ | 3.69 | $ | 3.34 | ||||||||
Discontinued operations | $ | (0.01 | ) | $ | 0.01 | $ | (0.02 | ) | $ | — | $ | (0.01 | ) | ||||||
Total | $ | (0.11 | ) | $ | 3.84 | $ | 2.59 | $ | 3.69 | $ | 3.33 | ||||||||
Diluted earnings per share | $ | (0.11 | ) | $ | 3.82 | $ | 2.58 | $ | 3.68 | $ | 3.31 | ||||||||
Dividends declared per share | $ | 1.285 | $ | 1.265 | $ | 1.245 | $ | 1.225 | $ | 1.175 | |||||||||
Total assets | $ | 48,039 | $ | 45,530 | $ | 41,444 | $ | 44,615 | $ | 37,523 | |||||||||
Long-term debt | $ | 13,689 | $ | 12,371 | $ | 10,437 | $ | 10,950 | $ | 9,016 | |||||||||
Preferred and preference stock of utility | $ | 1,029 | $ | 907 | $ | 907 | $ | 907 | $ | 915 | |||||||||
Common shareholders' equity | $ | 10,055 | $ | 10,583 | $ | 9,841 | $ | 9,517 | $ | 8,444 | |||||||||
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.
32
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
EDISON INTERNATIONAL OVERVIEW
Highlights of Operating Results
(in millions) | 2011 | 2010 | Change | 2009 | ||||||||
Net Income (Loss) attributable to Edison International | ||||||||||||
SCE | $ | 1,085 | $ | 1,040 | $ | 45 | $ | 1,226 | ||||
EMG | (1,089 | ) | 224 | (1,313 | ) | (395 | ) | |||||
Edison International Parent and Other | (33 | ) | (8 | ) | (25 | ) | 18 | |||||
Edison International Consolidated | (37 | ) | 1,256 | (1,293 | ) | 849 | ||||||
Less: Non-Core Items | ||||||||||||
Asset impairments and other charges: | ||||||||||||
EMG – Homer City Plant | (623 | ) | — | (623 | ) | — | ||||||
EMG – Fisk, Crawford and Waukegan Stations | (386 | ) | — | (386 | ) | — | ||||||
EMG – Wind related charges and other | (41 | ) | — | (41 | ) | — | ||||||
EMG – Write-down of net investment in aircraft leases | (16 | ) | — | (16 | ) | — | ||||||
EMG – Write-down of capitalized costs | — | (24 | ) | 24 | — | |||||||
EMG – Gain on sale of March Point | 5 | — | 5 | — | ||||||||
Global Settlement: | ||||||||||||
SCE | — | 95 | (95 | ) | 306 | |||||||
EMG1 | — | 52 | (52 | ) | (610 | ) | ||||||
Edison International Parent and Other | — | 28 | (28 | ) | 50 | |||||||
SCE – tax impact of health care legislation | — | (39 | ) | 39 | — | |||||||
SCE – regulatory items | — | — | — | 46 | ||||||||
Edison International Parent and Other – deferred taxes | (21 | ) | — | (21 | ) | — | ||||||
EMG discontinued operations | (3 | ) | 4 | (7 | ) | (7 | ) | |||||
Total non-core items | (1,085 | ) | 116 | (1,201 | ) | (215 | ) | |||||
Core Earnings (Losses) | ||||||||||||
SCE | 1,085 | 984 | 101 | 874 | ||||||||
EMG | (25 | ) | 192 | (217 | ) | 222 | ||||||
Edison International Parent and Other | (12 | ) | (36 | ) | 24 | (32 | ) | |||||
Edison International Consolidated | $ | 1,048 | $ | 1,140 | $ | (92 | ) | $ | 1,064 | |||
1 | Includes termination of Edison Capital's cross-border leases in 2009 and state tax impact of the Global Settlement with the IRS. |
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 (losses) 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 (losses) are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings (losses) 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: exit activities, including lease terminations, sale of certain assets, early debt extinguishment costs and other activities that are no longer continuing; asset impairments and certain tax, regulatory or legal settlements or proceedings.
SCE's 2011 core earnings increased $101 million primarily due to rate base growth.
EMG's 2011 core earnings declined $217 million due to lower realized energy and capacity prices along with lower
33
generation from merchant coal plants, higher plant maintenance costs from outages, higher interest expense related to renewable projects, and lower trading income.
Edison International Parent and Other 2011 core results changed primarily due to higher tax benefits in 2011 compared to 2010.
Consolidated non-core items for Edison International included:
• | An after-tax earnings charge of $1.09 billion ($1.76 billion pre-tax) recorded in the fourth quarter of 2011 resulting primarily from the impairment the Homer City, Fisk, Crawford and Waukegan power plants, wind related charges, write-down of a net investment in aircraft leases with American Airlines, and the impact on Edison International consolidated deferred income taxes resulting from an increase in the state apportionment rates due to such impairment charges as discussed further below and in "Item 8. Edison International Notes to Consolidated Financial Statements—Note 16. Asset Impairments, Lease Terminations and Other." |
• | An after tax earnings benefit of $175 million recorded in 2010 relating to the California impact of the federal Global Settlement resulting from acceptance by the California Franchise Tax Board of tax positions finalized with the IRS in 2009 and receipt of the final interest determination from the Franchise Tax Board. For further discussion of the Global Settlement, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 7. Income Taxes." |
• | An after-tax earnings charge of $39 million recorded in 2010 to reverse previously recognized federal tax benefits eliminated by federal health care legislation enacted in 2010. The health care law eliminated the federal tax deduction for retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies. |
• | An after-tax earnings charge of $24 million ($40 million pre-tax) recorded in 2010 resulting from the write-off of capitalized engineering and other costs related to a change in air emission control technology selection at EMG's Powerton Station. |
See "SCE: Results of Operations" for discussion of SCE results of operations, including a comparison of 2010 results to 2009. Also, see "EMG: Results of Operations" for discussion of EMG results of operations, including a comparison of 2010 results to 2009.
Management Overview of SCE
SCE's core mission is to deliver safe, reliable and affordable electric service to its customers. Accomplishing this mission requires balancing competing priorities, including public policies regarding air and water quality, energy efficiency and renewable energy and the need to replace aging infrastructure. The accumulation of several major policy mandates is expected to add significantly to the cost of electric service, which could cause a growing number of customers to seek to self-generate their power. Choices by customers to self-generate results in fewer kilowatt hour sales to absorb the increasing costs of the electrical system, further increasing rates for SCE's other customers. Working with policy makers to balance competing priorities, a key focus of SCE is to manage the costs that drive increases in electricity rates while delivering safe and reliable electric service to its customers.
2012 CPUC General Rate Case
SCE filed its 2012 GRC application in November 2010. In October 2011, SCE submitted updated testimony to reflect changes in escalation rates, known changes due to governmental actions and changes in the timing of recovery for nuclear refueling outages at San Onofre, which taken together changed its requested 2012 base rate revenue requirement to $6.3 billion. SCE's updated request, after considering the effects of sales growth and including the impacts of reducing SCE's solar program as approved by the CPUC, would result in incremental customer base rate increases of $809 million, $117 million and $513 million in 2012, 2013 and 2014, respectively.
The Division of Ratepayer Advocates ("DRA") recommended that SCE's requested 2012 base rate revenue requirement be decreased by approximately $850 million, comprised of approximately $630 million in operation and maintenance expense reductions and approximately $220 million in capital-related revenue requirement reductions. The Utility Reform Network ("TURN") and other intervenors recommended an additional $610 million revenue requirement reduction, beyond the DRA adjustments, primarily capital-related in nature, as well as disallowances of recorded capital investments for specific projects. Intervenors have also recommended changes to SCE's proposed post-test year ratemaking methodology to be used for 2013 and 2014 as well as limiting the recovery amount of SCE's pension costs. A final decision on the GRC is expected in the first half of 2012. The CPUC has authorized the establishment of a GRC memorandum account, which will make the 2012 revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012. Recognition of the revenue for the
34
period January 1, 2012 through the date of a final decision, as well as any delays in certain expenditures, may impact the timing of earnings in 2012.
FERC Formula Rates
The FERC has accepted, subject to refund and settlement procedures, SCE's request to implement formula rates as a means to determine SCE's FERC transmission revenue requirement effective January 1, 2012. The formula rates include revenue requirements related to construction work in progress ("CWIP") that was previously recovered through a separate mechanism. SCE estimates its total 2012 FERC weighted average ROE will be 11.1%, including the previously authorized 50 basis point incentive for CAISO participation and individual authorized project incentives. The actual weighted average ROE and rate base is dependent upon the amount and timing of capital expenditures among FERC incentive and non-incentive projects. SCE's request proposed the adoption of a specific formula to calculate a forecasted annual revenue requirement that is used to establish rates and is trued-up annually to allow SCE to recover its actual revenue requirement, including its actual cost of service, actual rate base and the authorized return on investment. SCE's request also allows SCE to make single-issue rate filings requesting changes to certain elements of the formula, including the base ROE, depreciation rates and the retail rate structure. SCE and the other parties to the proceeding are currently in settlement negotiations.
Capital Program
During 2011, SCE continued execution of its capital investment program. Total capital expenditures (including accruals) were $3.9 billion in 2011 compared to $3.8 billion in 2010. The level of future spending is significantly dependent on a final outcome of SCE's 2012 GRC decision and the timing, scope and approvals of major transmission projects. SCE's capital program for 2012 – 2014 is focused primarily in the following areas:
• | Maintaining reliability and expanding the capability of SCE's transmission and distribution system. |
• | Upgrading and constructing new transmission lines and substations for system reliability and increased access to renewable energy, including the Tehachapi, Devers-Colorado River, Eldorado-Ivanpah, and Red Bluff projects. |
• | Completing installation of digital meters in households and small businesses, referred to as EdisonSmartConnectTM. Through 2011, SCE installed 3.8 million meters and plans to install the remaining 1.2 million meters during 2012. |
• | Generation capital projects for nuclear and hydro-electric plants. |
SCE forecasts capital expenditures in the range of $11.8 billion to $13.2 billion for 2012 – 2014. Actual capital spending will be affected by: changes in regulatory, environmental and engineering design requirements; permitting and project delays; cost and availability of labor, equipment and materials; and other factors as discussed further under "SCE: Liquidity and Capital Resources—Capital Investment Plan." SCE has experienced significant cost pressures on its Tehachapi and Devers-Colorado River Transmission Projects, primarily related to environmental monitoring and mitigation costs, scope changes and schedule delays. Currently, SCE is completing the final engineering design for these projects and expects to file revised cost estimates with the CPUC later this year. Subject to further permitting and schedule delays, SCE has revised its direct capital expenditure estimates for the Tehachapi Project to $2.5 billion from $2.1 billion and revised its estimates for the Devers-Colorado River Project to $860 million from $649 million. The Tehachapi Project may be further impacted by issues related to aviation marking and lighting and community opposition to portions of the line, as further discussed in "SCE: Liquidity and Capital Resources—Capital Investment Plan." Capital program cost increases have been partially offset by expenditures for other transmission reliability projects, which were deferred due to delays from once-through cooling requirements for coastal generating plants. SCE plans to utilize cash generated from its operations, tax benefits and issuance of additional debt and preferred equity to fund its capital needs.
Management Overview of EMG
EMG's competitive power generation business primarily consists of the generation and sale into the PJM market of energy and capacity from merchant coal-fired power plants and a portfolio of natural gas and wind projects. EMG's operating results were significantly lower in 2011 compared to 2010 due to lower realized energy and capacity prices and generation at the coal plants. Power prices fell in the fourth quarter of 2011 and have continued to fall in 2012, driven by an abundance of low-priced natural gas, weather conditions and a slow economic recovery. Moreover, the abundance of low-priced natural gas has resulted in increased competition from natural gas-fired generating units in the markets in which Midwest Generation operates, and generation from Midwest Generation's plants has been correspondingly affected. Also at the end of 2011, a favorable long-term rail contract that supplied Midwest Generation's fleet expired and was replaced by a higher priced contract. EMG expects that Midwest Generation's average fuel cost ($/MWh) will increase by approximately one-third in 2012. Furthermore, Homer City is engaged in discussions with the owner-lessors regarding funding of retrofit expenditures
35
for the Homer City plant that, if successful in providing funding, will likely result in EME's loss of substantially all beneficial economic interest in and material control of the Homer City plant. Finally, as discussed below, EMG recorded significant impairment charges during the fourth quarter of 2011.
At December 31, 2011, EME had corporate cash and cash equivalents of $951 million and $498 million of available borrowing capacity under its $564 million revolving credit facility maturing in June 2012 and Midwest Generation had cash and cash equivalents of $213 million and $497 million of available borrowing capacity under its $500 million credit facility maturing in June 2012. Subsequent to the end of the fiscal year, EME terminated its revolving credit facility, and there can be no assurance that Midwest Generation will be eligible to draw on its credit facility prior to maturity. Any replacements of these credit lines will likely be on less favorable terms and conditions, and there is no assurance that EME will, or will be able to, replace these credit lines or any portion of them. EME had $3.7 billion of unsecured notes outstanding at December 31, 2011, $500 million of which mature in 2013.
Unless energy and capacity prices increase, EMG expects that it will incur further reductions in cash flow and losses in years subsequent to 2012 as well as in 2012, and a continuation of these adverse trends coupled with pending debt maturities and the need to retrofit its plants to comply with governmental regulations will strain EMG's liquidity. To address such scenario, EMG would need to consider all options available to it, including potential sales of assets or restructurings or reorganization of the capital structure of EMG and its subsidiaries. EMG's current business plans are focused on liquidity and operating effectively through the current commodity price cycle and on environmental compliance as described below.
Midwest Generation Environmental Compliance Plans and Costs
During 2011, Midwest Generation continued to advance necessary activities for NOx and SO2 controls to meet the requirements of the CPS. Midwest Generation does not anticipate a material change to its current approach in order to comply with the MATS rule. Midwest Generation expects to continue to develop and implement a compliance program that includes the operations of ACI systems, upgrades to particulate removal systems and the use of dry sorbent injection, combined with its use of low sulfur PRB coal, to meet emissions limits for criteria pollutants, such as NOx and SO2 as well as for hazardous air pollutants, such as mercury, acid gas and non-mercury metals.
A significant decline in power prices from September 30, 2011, combined with new environmental regulations and public policy pressure on coal generation have resulted in continuing uncertainties for merchant coal-fired power plants. Decisions regarding whether or not to proceed with retrofitting any particular remaining units to comply with CPS requirements for SO2 emissions, including those that have received permits, are subject to a number of factors, such as market conditions, regulatory and legislative developments, liquidity and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation may also elect to shut down units, instead of installing controls, to be in compliance with the CPS. Decisions about any particular combination of retrofits and shutdowns Midwest Generation may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital or continue with the expenditure of capital will be made as required, subject to the requirements of the CPS and other applicable regulations. In February 2012, Midwest Generation decided to shut down the Fisk Station by the end of 2012 and the Crawford Station by the end of 2014 and concluded it was less likely to retrofit the Waukegan Station rather than the larger Powerton, Joliet and Will County Stations. As a result, EMG recorded an impairment charge of $640 million at December 31, 2011 related to the Crawford, Fisk and Waukegan Stations. For further discussion, see "Edison International (Consolidated): Liquidity and Capital Resources—Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets—Application to Midwest Generation Stations" and "Item 8. Edison International Notes to Consolidated Financial Statements—Note 16. Asset Impairments, Lease Terminations and Other." Units that are not retrofitted may continue to operate until required to shut down by applicable regulations or operate with reduced output.
In connection with its decision to close the Fisk and Crawford Stations, Midwest Generation entered into a Memorandum of Understanding with the City of Chicago, acting through the Commissioner of Health, which acknowledges that the cessation of coal-fired electric generation at the Fisk and Crawford Stations will achieve the objectives of the proposed Chicago Clean Power Ordinance without a need to pass the proposed Clean Power Ordinance or similar ordinances (recognizing that such agreement cannot bind the Chicago City Council or its members). Midwest Generation and the City of Chicago have also agreed to collaborate with key stakeholders to consider potential future uses, ownership and sources of external funding to transition the sites for such uses. The closure of the Fisk and Crawford Stations will be subject to review for reliability by PJM Interconnection LLC, the regional transmission organization that controls the area where these plants are located. In total, Midwest Generation estimates 150 to 180 employees will be affected. The timing and amount of severance benefits, if any, will be determined after completion of review of personnel based on seniority and other factors and, in the case of the Crawford Station, the amount may be affected by the timing of the plant closure. Other obligations related to the Fisk and Crawford Stations could be affected by the plant closing, including sales of capacity, for which Midwest Generation is unable
36
to reasonably estimate the impact, or range of impacts, that could be incurred. Midwest Generation does not expect to incur future capital expenditures to close these plants.
Based on work to date, Midwest Generation estimates the cost of retrofitting the large stations (Powerton, Joliet Units 7 and 8 and Will County) using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions, and the associated upgrading of existing particulate removal systems, would be up to approximately $628 million. The cost of retrofitting Joliet Unit 6 is not included in the large unit amounts as it is less likely that Midwest Generation will make retrofits for this unit. The estimated cost of retrofitting Joliet Unit 6, if made, would be approximately $75 million, while the estimated cost of retrofitting the Waukegan Station, if made, would be approximately $160 million. For further discussion related to EMG's impairment policy on the unit of account, see "Edison International (Consolidated): Liquidity and Capital Resources—Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets."
In February 2012, Midwest Generation received an extension of its permit to install a dry sorbent injection system at the Powerton Station.
Homer City Lease
Homer City engaged a financial advisor and conducted a bidding process to obtain capital funding from third parties during the second half of 2011 to partially finance the installation of the environmental improvements. During the fourth quarter of 2011, such efforts failed to obtain sufficient interest from market participants necessary to fund the capital needed to make such improvements under the current lease arrangement. Homer City does not currently have sufficient capital and does not expect to generate sufficient funds from operations to complete retrofits. EMG is under no legal obligation to, and has chosen not to, provide funding. Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. Consequently, Homer City's ability to install environmental compliance equipment will be dependent on funding from the owner-lessors or third parties. Homer City is currently engaged in discussions with the owner-lessors regarding the potential for such funding. EMG expects that the outcome of any such discussions, if successful in providing funding for the Homer City plant, will likely result in EMG's loss of substantially all beneficial economic interest in and material control of the Homer City plant. Failure to resolve the source of funding of necessary capital expenditures for the Homer City plant could result in Homer City's default under the lease agreements giving rise to remedies for the owner-lessors and secured lease obligation bondholders, which could include foreclosing on the leased assets, the general partner of Homer City, or both.
There is no assurance that an agreement will be reached with the owner-lessors or the existing secured lease obligation bondholders on funding the capital improvements. Homer City believes it is unlikely to meet the covenant requirements of its sale-leaseback documents relating to the payment of equity rent at April 1, 2012 and will be unable to make the required equity rent payment. There is no assurance that subsequent rent payments will be made. Under the sale-leaseback documents, rent payments are comprised of two components, senior rent and equity rent. Senior rent is used exclusively for debt service to secured lease obligation bondholders, while equity rent is paid to the owner-lessors. In order to pay equity rent, among other requirements, Homer City must meet historical and projected senior rent service coverage ratios of 1.7 to 1 (subject to reduction to 1.3 to 1 under certain circumstances). A failure to pay equity rent does not entitle the owner-lessors to foreclose upon Homer City's leasehold interest, but it does result in the suspension of Homer City's ability to make permitted distributions. Moreover, Homer City would be permanently restricted in its ability to make permitted distributions if a failure to pay equity rent when due was not cured within nine months, or even if cured, occurred more than one additional time during the term of the lease. Homer City is not subject to any minimum historical and projected senior rent service coverage ratios except as conditions to distributions and equity rent payments. Also, failure by Homer City to pay equity rent when due in April 2012 could trigger termination of the $48 million senior rent reserve letter of credit. Homer City would then be required to fund the senior rent reserve, and failure to do so could entitle counterparties to seek available remedies under the sale-leaseback documents, including termination or foreclosure upon the leasehold interest. As a result of the expectation that EMG is likely to lose substantially all beneficial economic interest in and material control of the Homer City plant, EMG recorded an impairment charge of $1.03 billion for the fourth quarter of 2011. For further discussion, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 16. Asset Impairments, Lease Terminations and Other."
Included in the consolidated financial statements are the assets and liabilities related to Homer City. In the event that EMG no longer controls Homer City, EMG will record a loss on disposition of assets and liabilities and likely classify Homer City as a discontinued operation. The loss on disposition will be determined based on the assets and liabilities at the date of disposition and an assessment whether any ongoing contingencies exist. For further discussion, see "Edison International (Consolidated): Liquidity and Capital Resources—Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets—Application to Homer City Plant" and "Item 8. Edison International Notes to Consolidated Financial Statements—Note 16. Asset Impairments, Lease Terminations and Other."
37
As a result of the financial outlook of Homer City, as previously discussed, EMG's subsidiary, EMMT, has ceased to enter into hedging activities related to future power sales, but continues to enter into energy and capacity transactions on behalf of Homer City pursuant to an intercompany agreement. Those transactions are generally back-to-back transactions in which EMMT enters into a transaction with a third party as a principal and then enters into an equivalent transaction with Homer City. In the case of capacity, EMMT has sold Homer City capacity in the annual PJM base residual auctions through May 2015. If Homer City were to default on its obligations to supply capacity, then EMMT would be liable to PJM to supply that capacity, and failure to do so would expose EMMT to penalties under the PJM tariffs. If one or more of the Homer City units were to be unavailable as a capacity resource and EMMT did not fulfill this obligation through market transactions, then EMMT would be required to refund any capacity payments received and would be assessed by PJM a penalty equal to the greater of 20% of the capacity payments or $20 per MW-day.
EMG's Renewable Energy Activities
Recent developments related to EMG renewable financing and development activities include:
• | On December 21, 2011, EMG's subsidiary, EME closed a $242 million portfolio financing of three contracted wind projects representing 204 megawatts of generation capacity previously funded entirely with equity. Funding available in the amount of $110 million from the term loan facility, net of transaction costs, was distributed to EME in 2011 and approximately $95 million, net of transaction costs, of available funds is expected to be distributed in the first quarter of 2012 when the Pinnacle project achieves certain completion milestones. |
• | As part of its plan to obtain third-party equity capital to finance the development of a portion of EMG's wind portfolio, on February 13, 2012, Edison Mission Wind sold its indirect equity interests in the Cedro Hill wind project (150 MW in Texas), the Mountain Wind Power I project (61 MW in Wyoming) and the Mountain Wind Power II project (80 MW in Wyoming) to a new venture, Capistrano Wind Partners. Outside investors provided $238 million of the funding. Capistrano Wind Partners also agreed to acquire the Broken Bow I wind project (80 MW in Nebraska) and the Crofton Bluffs wind project (40 MW in Nebraska) for consideration expected to include $141 million from the same outside investors upon the satisfaction of specified conditions, including commencement of commercial operation and completion of project debt financing. The proceeds from outside investors net of costs on the projects to be completed are expected to be distributed to EMG and available for general corporate purposes. For additional information, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 3. Variable Interest Entities—Categories of Variable Interest Entities—Projects or Entities that are Consolidated." |
During the fourth quarter of 2011, EMG significantly reduced development of renewable energy projects to conserve cash and in light of more limited market opportunities. As a result, EMG reduced staffing and has undertaken efforts to reduce funding joint development projects, thereby reducing the development pipeline of potential wind projects to a projected installed capacity to approximately 1,300 megawatts. These changes triggered charges of $34 million. In addition, management has reviewed the Storm Lake project and four small wind projects in Minnesota, and based on an expected future increase in operating costs and declines in long-term power prices that the projects could potentially realize following the term of the power purchase agreements, EMG has recorded an impairment charge of $30 million. For additional information on renewable energy projects, see "EMG: Liquidity and Capital Resources—Capital Investment Plan," "Edison International (Consolidated): Critical Accounting Estimates and Policies—Impairment of Long-Lived Assets—Application to Selected Wind Projects," and "Item 8. Edison International Notes to Consolidated Financial Statements—Note 16. Asset Impairments, Lease Terminations and Other."
Environmental Developments
For a discussion of environmental developments, see "Item 8. Edison International Notes to Consolidated Financial Statements—Note 10. Environmental Developments."
38
SOUTHERN CALIFORNIA EDISON COMPANY
RESULTS OF OPERATIONS
SCE's results of operations are derived mainly through two sources:
• | Utility earning activities – representing revenue authorized by the CPUC and FERC which is intended to provide SCE a reasonable opportunity to recover its costs and earn a return on its net investment in generation, transmission and distribution assets. The annual revenue requirements are comprised of forecasted operation and maintenance costs, depreciation, taxes and a return consistent with the capital structure. Also, included in utility earnings activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any. |
• | Utility cost-recovery activities – representing CPUC- and FERC-authorized balancing accounts which allow for recovery of specific project or program costs incurred or provide for mechanisms to track and recover or refund differences in forecasted and actual amounts, subject to reasonableness review or compliance with upfront standards. |
39
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.
2011 | 2010 | 2009 | |||||||||||||||||||||||||
(in millions) | Utility Earning Activities | Utility Cost- Recovery Activities | Total Consolidated | Utility Earning Activities | Utility Cost- Recovery Activities | Total Consolidated | Utility Earning Activities | Utility Cost- Recovery Activities1,2 | Total Consolidated | ||||||||||||||||||
Operating revenue | $ | 5,902 | $ | 4,675 | $ | 10,577 | $ | 5,606 | $ | 4,377 | $ | 9,983 | $ | 5,303 | $ | 4,662 | $ | 9,965 | |||||||||
Fuel and purchased power | — | 3,356 | 3,356 | — | 3,293 | 3,293 | — | 3,472 | 3,472 | ||||||||||||||||||
Operations and maintenance | 2,208 | 1,179 | 3,387 | 2,271 | 1,020 | 3,291 | 2,111 | 1,043 | 3,154 | ||||||||||||||||||
Depreciation decommissioning and amortization | 1,294 | 132 | 1,426 | 1,213 | 60 | 1,273 | 1,124 | 54 | 1,178 | ||||||||||||||||||
Property taxes and other | 277 | 8 | 285 | 260 | 3 | 263 | 244 | — | 244 | ||||||||||||||||||
Gain on sale of assets | — | — | — | — | (1 | ) | (1 | ) | — | (1 | ) | (1 | ) | ||||||||||||||
Total operating expenses | 3,779 | 4,675 | 8,454 | 3,744 | 4,375 | 8,119 | 3,479 | 4,568 | 8,047 | ||||||||||||||||||
Operating income | 2,123 | — | 2,123 | 1,862 | 2 | 1,864 | 1,824 | 94 | 1,918 | ||||||||||||||||||
Net interest expense and other | (378 | ) | — | (378 | ) | (330 | ) | (2 | ) | (332 | ) | (298 | ) | — | (298 | ) | |||||||||||
Income before income taxes | 1,745 | — | 1,745 | 1,532 | — | 1,532 | 1,526 | 94 | 1,620 | ||||||||||||||||||
Income tax expense | 601 | — | 601 | 440 | — | 440 | 249 | — | 249 | ||||||||||||||||||
Net income | 1,144 | — | 1,144 | 1,092 | — | 1,092 | 1,277 | 94 | 1,371 | ||||||||||||||||||
Net income attributable to noncontrolling interest | — | — | — | — | — | — | — | 94 | 94 | ||||||||||||||||||
Dividends on preferred and preference stock | 59 | — | 59 | 52 | — | 52 | 51 | — | 51 | ||||||||||||||||||
Net income available for common stock | $ | 1,085 | $ | — | $ | 1,085 | $ | 1,040 | $ | — | $ | 1,040 | $ | 1,226 | $ | — | $ | 1,226 | |||||||||
Core Earnings3 | $ | 1,085 | $ | 984 | $ | 874 | |||||||||||||||||||||
Non-Core Earnings: | |||||||||||||||||||||||||||
Global tax settlement | — | 95 | 306 | ||||||||||||||||||||||||
Tax impact of health care legislation | — | ||||||||||||||||||||||||||