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UNITED STATESSECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
Commission File Number 1-9936
EDISON INTERNATIONAL (Exact name of registrant as specified in its charter)
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 ý No o
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No o
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.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ý
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
TABLE OF CONTENTS
GLOSSARY
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
Consolidated Statements of Income
Consolidated Statements of Comprehensive Income
Consolidated Balance Sheets
Consolidated Statements of Cash Flows
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Accounting Policies
Note 2. Consolidated Statements of Changes in Equity
Note 3. Variable Interest Entities
Note 4. Fair Value Measurements
Note 5. Debt and Credit Agreements
Note 6. Derivative Instruments and Hedging Activities
Note 7. Income Taxes
Note 8. Compensation and Benefit Plans
Note 9. Commitments and Contingencies
Note 10. Regulatory and Environmental Developments
Note 11. Accumulated Other Comprehensive Income (Loss)
Note 12. Supplemental Cash Flows Information
Note 13. Preferred and Preference Stock of Utility
Note 14. Regulatory Assets and Liabilities
Note 15. Other Investments
Note 16. Other Income and Expenses
Note 17. Business Segments
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
EDISON INTERNATIONAL MANAGEMENT OVERVIEW
Highlights of Operating Results
Management Overview of SCE
Capital Program
2012 CPUC General Rate Case
Nuclear Industry and Regulatory Response to Events in Japan
Management Overview of EMG
Midwest Generation Environmental Compliance Plans and Costs
Homer City Outage
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Environmental Regulation Developments
SOUTHERN CALIFORNIA EDISON COMPANY
RESULTS OF OPERATIONS
Electric Utility Results of Operations
Utility Earning Activities
2011 vs. 2010
Utility Cost-Recovery Activities
Supplemental Operating Revenue Information
Income Taxes
LIQUIDITY AND CAPITAL RESOURCES
Available Liquidity
Debt Covenant
Dividend Restrictions
Margin and Collateral Deposits
Derivative Instruments and Power Procurement Contracts
Workers Compensation Self-Insurance Fund
Historical Consolidated Cash Flows
Condensed Consolidated Statement of Cash Flows
Net Cash Provided by Operating Activities
Net Cash Provided by Financing Activities
Net Cash Used by Investing Activities
Contractual Obligations and Contingencies
Contractual Obligations
Contingencies
Environmental Remediation
MARKET RISK EXPOSURES
Commodity Price Risk
Credit Risk
EDISON MISSION GROUP
Results of Continuing Operations
Adjusted Operating Income ("AOI") —Overview
Adjusted Operating Income from Consolidated Operations
Midwest Generation Plants
Homer City
Seasonality—Coal Plants
Renewable Energy Projects
Energy Trading
Adjusted Operating Income from Unconsolidated Affiliates
Interest Expense
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Results of Discontinued Operations
Capital Investment Plan
Environmental Capital Expenditures
Non-Environmental Capital Expenditures
Future Projects
Historical Segment Cash Flows
Condensed Statement of Cash Flows
Net Cash Provided by Investing Activities
Credit Ratings
Overview
Credit Rating of EMMT
Margin, Collateral Deposits and Other Credit Support for Energy Contracts
Debt Covenants and Dividend Restrictions
Credit Facility Financial Ratios
Key Ratios of EMG's Principal Subsidiaries Affecting Dividends
EMG's Senior Notes and Guaranty of Powerton-Joliet Leases
Fuel Supply Contracts
Midwest Generation New Source Review Lawsuit
Homer City New Source Review Lawsuit
Off-Balance Sheet Transactions
Derivative Instruments
Unrealized Gains and Losses
Fair Value Disclosures
Energy Price Risk Affecting Sales from the Coal Plants
Capacity Price Risk
Basis Risk
Coal and Transportation Price Risk
Emission Allowances Price Risk
Interest Rate Risk
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EDISON INTERNATIONAL PARENT AND OTHER
Historical Cash Flows
Net Cash Used by Operating Activities
Net Cash Provided (Used) by Financing Activities
EDISON INTERNATIONAL (CONSOLIDATED)
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
NEW ACCOUNTING GUIDANCE
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 4. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
California Coastal Commission Potential Environmental Proceeding
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
ITEM 6. EXHIBITS
SIGNATURE
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When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
v
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Electric utility
Competitive power generation
Other
Total operating revenue
Fuel
Purchased power
Operations and maintenance
Depreciation, decommissioning and amortization
Lease terminations and other
Total operating expenses
Operating income
Interest and dividend income
Equity in income (loss) from unconsolidated affiliates – net
Other income
Interest expense – net of amounts capitalized
Other expenses
Income from continuing operations before income taxes
Income tax expense
Income from continuing operations
Income (loss) from discontinued operations – net of tax
Net income
Dividends on preferred and preference stock of utility
Net income attributable to Edison International common shareholders
Amounts attributable to Edison International common shareholders:
Income from continuing operations, net of tax
Income (loss) from discontinued operations, net of tax
Basic earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding
Continuing operations
Discontinued operations
Total
Diluted earnings per common share attributable to Edison International common shareholders:
Weighted-average shares of common stock outstanding, including effect of dilutive securities
Dividends declared per common share
The accompanying notes are an integral part of these consolidated financial statements.
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Other comprehensive income (loss), net of tax:
Pension and postretirement benefits other than pensions:
Net gain arising during the period
Amortization of net (gain) loss included in net income
Prior service credit arising during the period
Amortization of prior service credit
Unrealized gain (loss) on derivatives qualified as cash flow hedges:
Unrealized holding gain arising during the period, net of income tax expense of $4 and $62 for 2011 and 2010, respectively
Reclassification adjustments included in net income, net of income tax benefit of $6 and $14 for 2011 and 2010, respectively
Other comprehensive income (loss)
Comprehensive income
Less: Comprehensive income attributable to noncontrolling interests
Comprehensive income attributable to Edison International
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ASSETS
Cash and cash equivalents
Receivables, less allowances of $87 and $85 for uncollectible accounts at respective dates
Accrued unbilled revenue
Inventory
Prepaid taxes
Derivative assets
Restricted cash
Margin and collateral deposits
Regulatory assets
Other current assets
Total current assets
Nuclear decommissioning trusts
Investments in unconsolidated affiliates
Other investments
Total investments
Utility property, plant and equipment, less accumulated depreciation of $6,488 and $6,319 at respective dates
Competitive power generation and other property, plant and equipment, less accumulated depreciation of $1,940 and $1,865 at respective dates
Total property, plant and equipment
Restricted deposits
Rent payments in excess of levelized rent expense under plant operating leases
Other long-term assets
Total long-term assets
Total assets
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LIABILITIES AND EQUITY
Short-term debt
Current portion of long-term debt
Accounts payable
Accrued taxes
Accrued interest
Customer deposits
Derivative liabilities
Regulatory liabilities
Other current liabilities
Total current liabilities
Long-term debt
Deferred income taxes
Deferred investment tax credits
Customer advances
Pensions and benefits
Asset retirement obligations
Other deferred credits and other long-term liabilities
Total deferred credits and other liabilities
Total liabilities
Commitments and contingencies (Note 9)
Common stock, no par value (800,000,000 shares authorized; 325,811,206 shares issued and outstanding at each date)
Accumulated other comprehensive loss
Retained earnings
Total Edison International's common shareholders' equity
Preferred and preference stock of utility
Other noncontrolling interests
Total noncontrolling interests
Total equity
Total liabilities and equity
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Cash flows from operating activities:
Less: Income (loss) from discontinued operations
Adjustments to reconcile to net cash provided by operating activities:
Regulatory impacts of net nuclear decommissioning trust earnings (reflected in accumulated depreciation)
Other amortization
Stock-based compensation
Distributions and dividends from unconsolidated entities
Deferred income taxes and investment tax credits
Income from leveraged leases
Changes in operating assets and liabilities:
Receivables
Margin and collateral deposits – net of collateral received
Rent payments in excess of levelized rent expense
Derivative assets and liabilities – net
Regulatory assets and liabilities – net
Other assets
Other liabilities
Operating cash flows from discontinued operations
Net cash provided by operating activities
Cash flows from financing activities:
Long-term debt issued
Long-term debt issuance costs
Long-term debt repaid
Preference stock issued
Short-term debt financing – net
Settlements of stock-based compensation – net
Dividends and distributions to noncontrolling interests
Dividends paid
Net cash provided by financing activities
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Cash flows from investing activities:
Capital expenditures
Proceeds from sale of nuclear decommissioning trust investments
Purchases of nuclear decommissioning trust investments and other
Proceeds from partnerships and unconsolidated subsidiaries, net of investment
Investments in other assets
Effect of consolidation and deconsolidation of variable interest entities
Net cash used by investing activities
Net decrease in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Unaudited)
Edison International has two business segments for financial reporting purposes: an electric utility operation 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. EMG is the holding company for its principal wholly owned subsidiary, EME. EME is a holding company with subsidiaries and affiliates engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EME also engages in hedging and energy trading activities in competitive power markets through its Edison Mission Marketing & Trading, Inc. ("EMMT") subsidiary.
Basis of Presentation
Edison International's significant accounting policies were described in Note 1 of "Edison International Notes to Consolidated Financial Statements" included in the 2010 Form 10-K. Edison International follows the same accounting policies for interim reporting purposes, with the exception of accounting principles adopted as of January 1, 2011, discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with the financial statements and notes included in the 2010 Form 10-K.
In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to fairly state the consolidated financial position, results of operations and cash flows in accordance with accounting principles generally accepted in the United States of America for the periods covered by this quarterly report on Form 10-Q. The results of operations for the three month period ended March 31, 2011 are not necessarily indicative of the operating results for the full year.
The December 31, 2010 condensed consolidated balance sheet data was derived from audited financial statements, but does not include all disclosures required by accounting principles generally accepted in the United States of America.
Cash Equivalents
Cash equivalents included investments in money market funds totaling $1.0 billion and $1.1 billion at March 31, 2011 and December 31, 2010, respectively. Generally, the carrying value of cash equivalents equals the fair value, as all investments have maturities of three months or less.
Edison International temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. Edison International reclassified $207 million and $197 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at March 31, 2011 and December 31, 2010, respectively.
Inventory is stated at the lower of cost or market, cost being determined by the weighted-average cost method for fuel, and the average cost method for materials and supplies. Inventory consisted of the following:
Coal, gas, fuel oil and other raw materials
Spare parts, materials and supplies
Total inventory
Earnings Per Share
Edison International computes EPS using the two-class method, which is an earnings allocation formula that determines EPS for each class of common stock and participating security. Edison International's
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participating securities are stock-based compensation awards payable in common shares, including stock options, performance shares and restricted stock units, which earn dividend equivalents on an equal basis with common shares. Stock options awarded during the period 2003 through 2006 received dividend equivalents. EPS attributable to Edison International common shareholders was computed as follows:
Basic earnings per share – continuing operations:
Income from continuing operations attributable to common shareholders, net of tax
Participating securities dividends
Income from continuing operations available to common shareholders
Weighted average common shares outstanding
Basic earnings per share – continuing operations
Diluted earnings per share – continuing operations:
Income impact of assumed conversions
Income from continuing operations available to common shareholders and assumed conversions
Incremental shares from assumed conversions
Adjusted weighted average shares – diluted
Diluted earnings per share – continuing operations
Stock-based compensation awards to purchase 8,980,322 and 5,998,238 shares of common stock were outstanding for the three months ended March 31, 2011 and 2010, respectively, but were not included in the computation of diluted earnings per share because the exercise price of the awards was greater than the average market price of the common shares and, therefore, the effect would have been antidilutive.
New Accounting Guidance
Accounting Guidance Adopted in 2011
Revenue—Multiple-Deliverables
In October 2009, the Financial Accounting Standards Board (FASB) issued amended guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenues based on those separate deliverables. This update also requires additional disclosure related to the significant assumptions used to determine the revenue recognition of the separate deliverables. This guidance is required to be applied prospectively to new or significantly modified revenue arrangements. Edison International adopted this guidance effective January 1, 2011. The adoption of this accounting standards update did not have a material impact on Edison International's consolidated results of operations, financial position or cash flows.
Fair Value Measurements and Disclosures
The FASB issued an accounting standards update modifying the disclosure requirements related to fair value measurements. Under these requirements, purchases and settlements for Level 3 fair value measurements are presented on a gross basis, rather than net. Edison International adopted this guidance effective January 1, 2011.
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The following table provides the changes in equity for the three months ended March 31, 2011.
Balance at December 31, 2010
Net income (loss)
Other comprehensive loss
Common stock dividends declared ($0.32 per share)
Dividends, distributions to noncontrolling interests and other
Stock-based compensation and other
Noncash stock-based compensationand other
Issuance of preference stock
Balance at March 31, 2011
The following table provides the changes in equity for the three months ended March 31, 2010:
Balance at December 31, 2009
Other comprehensive income
Deconsolidation of variable interest entities
Cumulative effect of a change in accounting principle, net of tax
Common stock dividends declared ($0.315 per share)
Balance at March 31, 2010
A variable interest entity ("VIE") is defined as a legal entity whose equity owners do not have sufficient equity at risk, or, as a group, the holders of the equity investment at risk lack any of the following three characteristics: decision-making rights, the obligation to absorb losses, or the right to receive the expected residual returns of the entity. The primary beneficiary is identified as the variable interest holder that has both the power to direct the activities of the VIE that most significantly impact the entity's economic performance and the obligation to absorb losses or the right to receive benefits from the entity that could potentially be significant to the VIE. The primary beneficiary is required to consolidate the VIE.
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Commercial and operating activities are generally the factors that most significantly impact the economic performance of VIEs in which Edison International has a variable interest. Commercial and operating activities include construction, operation and maintenance, fuel procurement, dispatch and compliance with regulatory and contractual requirements.
Categories of Variable Interest Entities
Projects or Entities that are Consolidated
At March 31, 2011 and December 31, 2010, EMG consolidated 13 wind projects with a total generating capacity of 500 MW that have minority interests held by others. EMG also had a 50% partnership interest in the American Bituminous Power Partners, L.P. project, commonly referred to as the Ambit project.
The following table presents summarized financial information of the projects that were consolidated by EMG:
Current assets
Net property, plant and equipment
Current liabilities
Long-term debt net of current maturities
Deferred revenues
Other long-term liabilities
Noncontrolling interests
Assets serving as collateral for the debt obligations had a carrying value of $167 million and $163 million at March 31, 2011 and December 31, 2010, respectively, and primarily consist of property, plant and equipment.
Variable Interest in VIEs that are not Consolidated
Power Purchase Contracts
SCE has 16 power purchase agreements ("PPAs") that are considered variable interests in VIEs, including 6 tolling agreements through which SCE provides the natural gas to operate the plants and 10 contracts with QFs that contain variable pricing provisions based on the price of natural gas. SCE has concluded that it is not the primary beneficiary of these VIEs since it does not control the commercial and operating activities of these entities. In general, because payments for capacity are the primary source of income, the most significant economic activity for SCE's VIEs is the operation and maintenance of the power plants.
As of the balance sheet date, the carrying amount of assets and liabilities in SCE's consolidated balance sheet that relate to its involvement with VIEs result from amounts due under the PPAs or the fair value of those derivative contracts. These are accounted for at fair value. Under these contracts, SCE recovers the costs incurred under its approved long-term power procurement plans. SCE has no residual interest in the entities and has not provided or guaranteed any debt or equity support, liquidity arrangements, performance guarantees or other commitments associated with these contracts other than the purchase commitments described in Note 9, so there is no significant potential exposure to loss as a result of SCE's involvement with these VIEs. The aggregate capacity dedicated to SCE for these VIE projects was 3,820 MW at March 31, 2011 and the amounts that SCE paid to these projects were $86 million and $125 million for the three months ended March 31, 2011 and 2010, respectively. These amounts are recovered in customer rates.
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Equity Interests
EMG accounts for domestic energy projects in which it has a 50% or less ownership interest, and cannot exercise unilateral control, under the equity method. At March 31, 2011 and December 31, 2010, EMG had five significant variable interests in natural gas projects that are not consolidated, consisting of the Big 4 projects (Kern River, Midway-Sunset, Sycamore and Watson) and the Sunrise project. A subsidiary of EMG operates three of the four Big 4 projects and EMG's partner provides the fuel management services. In addition, the executive director of these projects is provided by EMG's partner. Commercial and operating activities are jointly controlled by a management committee of each VIE. Accordingly, EMG continues to account for its variable interests under the equity method.
At March 31, 2011 and December 31, 2010, EMG accounts for its interests in two renewable wind generating facilities, the Elkhorn Ridge and San Juan Mesa projects, under the equity method. The commercial and operating activities of these entities are directed by a management committee composed of representatives of each partner. Thus, EMG is not the primary beneficiary of these projects. In addition, EMG accounts for its interests in a wind project under construction, Community Wind North, under the equity method.
The following table presents the carrying amount of EMG's investments in unconsolidated VIEs and the maximum exposure to loss for each investment:
Natural gas-fired projects
Renewable energy projects
EMG's maximum exposure to loss in its VIEs accounted for under the equity method is generally limited to its investment in these entities. Two of EMG's domestic energy projects have long-term debt that is secured by a pledge of assets of the project entity, but does not provide for recourse to EMG. Accordingly, a default under such project financings could result in foreclosure on the assets of the project entity resulting in a loss of some or all of EMG's investment, but would not require EMG to contribute additional capital. At March 31, 2011, entities which EMG has accounted for under the equity method had indebtedness of $115 million, of which $41 million is proportionate to EMG's ownership interest in these two projects.
Recurring Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an "exit price"). Fair value of an asset or liability should consider assumptions that market participants would use in pricing the asset or liability, including assumptions about nonperformance risk.
Edison International categorizes financial assets and liabilities into a fair value hierarchy based on valuation inputs used to derive fair value. The hierarchy gives the highest priority to unadjusted quoted market prices in active markets for identical assets and liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).
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The following table sets forth assets and liabilities that were accounted for at fair value by level within the fair value hierarchy:
Assets at Fair Value
Money market funds2
Derivative contracts:
Electricity
Natural gas
Fuel oil
Tolling
Subtotal of commodity contracts
Long-term disability plan
Nuclear decommissioning trusts:
Stocks3
Municipal bonds
Corporate bonds4
U.S. government and agency securities
Short-term investments, primarily cash equivalents5
Subtotal of nuclear decommissioning trusts
Total assets6
Liabilities at Fair Value
Interest rate contracts
Net assets (liabilities)
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Coal
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The following table sets forth a summary of changes in the fair value of Level 3 assets and liabilities:
Fair value, net asset at beginning of period
Total realized/unrealized gains (losses):
Included in earnings1
Included in regulatory assets and liabilities2
Included in accumulated other comprehensive income
Purchases
Settlements
Transfers in or out of Level 3
Fair value, net liability at end of period
Change during the period in unrealized losses related to assets and liabilities held at the end of the period3
Edison International determines the fair value for transfers in and transfers out of each level at the end of each reporting period. There were no significant transfers between levels during 2011 and 2010.
Valuation Techniques Used to Determine Fair Value
Level 1
Includes assets and liabilities where fair value is determined using unadjusted quoted prices in active markets that are available at the measurement date for identical assets and liabilities. Financial assets and liabilities classified as Level 1 include exchange-traded equity securities, exchange traded derivatives, U.S. treasury securities and money market funds.
Level 2
Pricing inputs include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the derivative instrument. Financial assets and liabilities utilizing Level 2 inputs include fixed-income securities and over-the-counter derivatives.
Derivative contracts that are over-the-counter traded are valued using pricing models to determine the net present value of estimated future cash flows and are generally classified as Level 2. Inputs to the pricing models include forward published or posted clearing prices from exchanges (New York Mercantile Exchange and Intercontinental Exchange) for similar instruments and discount rates. A primary source that best represents traded activity for each market is used to develop observable forward market prices in determining the fair value of these positions. Broker quotes or prices from exchanges are used to validate and corroborate the primary source. These price quotations reflect mid-market prices (average of bid and ask) and are obtained from sources believed to provide the most liquid market for the commodity. Broker quotes are incorporated when corroborated with other information which may include a combination of prices from exchanges, other brokers and comparison to executed trades.
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Level 3
Includes financial assets and liabilities where fair value is determined using techniques that require significant unobservable inputs. Over-the-counter options, bilateral contracts, capacity contracts, QF contracts, derivative contracts that trade infrequently (such as congestion revenue rights ("CRRs") in the California market and over-the-counter derivatives at illiquid locations), long-term power agreements, and derivative contracts with counterparties that have significant nonperformance risks are generally valued using pricing models that incorporate unobservable inputs and are classified as Level 3. Assumptions are made in order to value derivative contracts in which observable inputs are not available. In circumstances where Edison International cannot verify fair value with observable market transactions, it is possible that a different valuation model could produce a materially different estimate of fair value. As markets continue to develop and more pricing information becomes available, Edison International continues to assess valuation methodologies used to determine fair value.
For derivative contracts that trade infrequently (illiquid financial transmission rights and CRRs), changes in fair value are based on models forecasting the value of those contracts. The models' inputs are reviewed and the fair value is adjusted when it is concluded that a change in inputs would result in a new valuation that better reflects the fair value of those derivative contracts. For illiquid long-term power agreements, fair value is based upon the discounting of future electricity and natural gas prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit risk and market liquidity. Changes in fair value are based on changes to forward market prices, including forecasted prices for illiquid forward periods. The fair value of the majority of SCE's derivatives that are classified as Level 3 is determined using uncorroborated non-binding broker quotes and models which may require SCE to extrapolate short-term observable inputs in order to calculate fair value. Broker quotes are obtained from several brokers and compared against each other for reasonableness.
Nonperformance Risk
The fair value of the derivative assets and liabilities are adjusted for nonperformance risk. To assess nonperformance risks, SCE considers the probability of and the estimated loss incurred if a party to the transaction were to default. SCE also considers collateral, netting agreements, guarantees and other forms of credit support when assessing nonperformance. EMG reviews credit ratings of counterparties (and related default rates based on such credit ratings) and prices of credit default swaps. The market price (or premium) for credit default swaps represents the price that a counterparty would pay to transfer the risk of default, typically bankruptcy, to another party. A credit default swap is not directly comparable to the credit risks of derivative contracts, but provides market information of the related risk of nonperformance. The nonperformance risk adjustment represented an insignificant amount at both March 31, 2011 and December 31, 2010.
Nuclear Decommissioning Trusts
SCE's nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed-income securities. Equity and treasury securities are classified as Level 1 as fair value is determined by observable market prices in active or highly liquid and transparent markets. The remaining fixed-income securities are classified as Level 2. The fair value of these financial instruments is based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes, issuer spreads, bids, offers and relevant credit information.
Fair Value of Long-Term Debt Recorded at Carrying Value
The carrying amounts and fair values of long-term debt are:
Long-term debt, including current portion
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Fair values of long-term debt are based on evaluated prices that reflect significant observable market information such as reported trades, actual trade information of similar securities, benchmark yields, broker/dealer quotes of new issue prices and relevant credit information.
The carrying value of trade receivables, payables and short-term debt approximates fair value.
Project Financings
In February 2011, EME completed, through its subsidiary, Viento Funding II, Inc., an amendment of its 2009 non-recourse financing of its interests in the Wildorado, San Juan Mesa and Elkhorn Ridge wind projects. The amendment increased the financing amount to $255 million, which included a $227 million ten-year term loan (expiring in December 2020), a $23 million seven-year letter of credit facility and a $5 million seven-year working capital facility. At March 31, 2011, $227 million was outstanding under this loan. The amount of outstanding letters of credit was $13 million. Interest under the term loan accrues at London Interbank Offered Rate (LIBOR) plus 2.75% initially with the rate increasing 0.25% on every fourth anniversary.
Credit Agreements
At March 31, 2011, SCE's outstanding short-term debt was $200 million at a weighted-average interest rate of 0.35%. This short-term debt was supported by a $2.4 billion credit facility. At December 31, 2010, there was no outstanding short-term debt. At March 31, 2011, letters of credit issued under SCE's credit facilities aggregated $73 million and are scheduled to expire in twelve months or less.
As of March 31, 2011, a subsidiary of EMG had a $10 million letter of credit facility with $2 million outstanding letters of credit.
At March 31, 2011, Edison International (Parent)'s outstanding short-term debt was $81 million at a weighted-average interest rate of 0.61%. At December 31, 2010, the outstanding short-term debt was $19 million at a weighted-average interest rate of 0.63%.
Letters of Credit
At March 31, 2011, standby letters of credit under EME's credit facility aggregated $80 million and were scheduled to expire as follows: $53 million in 2011 and $27 million in 2012. In addition, letters of credit under EME's subsidiaries' credit facilities aggregated $41 million, $3 million of which was under the Midwest Generation, LLC (Midwest Generation) credit facility, and were scheduled to expire as follows: $7 million in 2011, $16 million in 2012, $10 million in 2017, and $8 million in 2018. Certain letters of credit are subject to automatic annual renewal provisions.
Electric Utility
SCE is exposed to commodity price risk which represents the potential impact that can be caused by a change in the market value of a particular commodity. SCE's hedging program reduces ratepayer exposure to variability in market prices related to SCE's power and gas activities. As part of this program, SCE enters into energy options, swaps, forward arrangements, tolling arrangements and CRRs. These transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans. SCE recovers its related hedging costs through the ERRA balancing account, and as a result, exposure to commodity price risk is not expected to impact earnings, but may impact cash flows.
SCE's electricity price exposure arises from electricity purchased from the California wholesale market as a result of differences between SCE's load requirements and the amount of energy delivered from its generating facilities, power purchase agreements and CDWR contracts allocated to SCE.
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SCE's natural gas price exposure arises from natural gas purchased for generation at the Mountainview power plant and peaker plants, QF contracts where pricing is based on a monthly natural gas index and power purchase agreements in which SCE has agreed to provide the natural gas needed for generation, referred to as tolling arrangements.
Notional Volumes of Derivative Instruments
The following table summarizes the notional volumes of derivatives used for hedging activities:
Electricity options, swaps and forwards
Natural gas options, swaps and forwards
Congestion revenue rights
Tolling arrangements
Fair Value of Derivative Instruments
The following table summarizes the gross and net fair values of commodity derivative instruments at March 31, 2011:
Non-trading activities
Economic hedges
Netting and collateral
The following table summarizes the gross and net fair values of commodity derivative instruments at December 31, 2010:
Income Statement Impact of Derivative Instruments
SCE recognizes realized gains and losses on derivative instruments as purchased-power expense and expects to recover these costs from ratepayers. As a result, realized gains and losses are not reflected in earnings, but may temporarily affect cash flows. Due to expected future recovery from ratepayers, unrealized gains and losses are recorded as regulatory assets and liabilities and therefore are also not reflected in earnings. The results of derivative activities and related regulatory offsets are recorded in cash flows from operating activities in the consolidated statements of cash flows.
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The following table summarizes the components of economic hedging activity:
Realized losses
Unrealized losses
Contingent Features/Credit Related Exposure
Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. SCE has historically provided collateral in the form of cash and/or letters of credit for the benefit of counterparties. These requirements can vary depending upon the level of unsecured credit extended by counterparties, changes in market prices relative to contractual commitments and other factors.
Certain of these power contracts contain a provision that requires SCE to maintain an investment grade credit rating from each of the major credit rating agencies, referred to as a "credit-risk-related contingent feature." If SCE's credit rating were to fall below investment grade, SCE may be required to pay the derivative liability or post additional collateral. The aggregate fair value of all derivative liabilities with these credit-risk-related contingent features was $82 million and $67 million as of March 31, 2011 and December 31, 2010, respectively, for which SCE has posted no collateral and $4 million of collateral to its counterparties for the respective periods. If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2011, SCE would be required to post $2 million of collateral.
Counterparty Default Risk Exposure
As part of SCE's procurement activities, SCE contracts with a number of utilities, energy companies, financial institutions, and other companies, collectively referred to as counterparties. If a counterparty were to default on its contractual obligations, SCE could be exposed to potentially volatile spot markets for buying replacement power or selling excess power. In addition, SCE would be exposed to the risk of non-payment of accounts receivable, primarily related to sales of excess energy and realized gains on derivative instruments. However, all of the contracts that SCE has entered into with counterparties are either entered into under SCE's short-term or long-term procurement plan which has been approved by the CPUC, or the contracts are approved by the CPUC before becoming effective. As a result of regulatory recovery mechanisms, losses from non-performance are not expected to affect earnings, but may temporarily affect cash flows.
To manage credit risk, SCE looks at the risk of a potential default by counterparties. Credit risk is measured by the loss that would be incurred if counterparties failed to perform pursuant to the terms of their contractual obligations. To mitigate credit risk from counterparties, master netting agreements are used whenever possible and counterparties may be required to pledge collateral when deemed necessary.
Competitive Power Generation
EMG uses derivative instruments to reduce EMG's exposure to market risks that arise from price fluctuations of electricity, capacity, fuel, emission allowances, and transmission rights. Additionally, EMG's financial results can be affected by fluctuations in interest rates. The derivative financial instruments vary in duration, ranging from a few days to several years, depending upon the instrument. To the extent that EMG does not use derivative instruments to hedge these market risks, the unhedged portions will be subject to the risks and benefits of spot market price movements.
Risk management positions may be designated as cash flow hedges or economic hedges, which are derivatives that are not designated as cash flow hedges. Economic hedges are accounted for at fair value on Edison International's consolidated balance sheets with offsetting changes recorded on the consolidated statements of income. For derivative instruments that qualify for hedge accounting treatment, the fair value is recognized, to the extent effective, on Edison International's consolidated balance sheets with offsetting changes in fair value recognized in accumulated other comprehensive income until the related forecasted
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transaction occurs. The results of derivative activities are recorded in cash flows from operating activities on the consolidated statements of cash flows.
Derivative instruments that are utilized for trading purposes are measured at fair value and included on the consolidated balance sheets as derivative assets or liabilities. Changes in fair value are recognized in operating revenues on the consolidated statements of income.
Where EMG's derivative instruments are subject to a master netting agreement and the criteria of authoritative guidance are met, EMG presents its derivative assets and liabilities on a net basis on the consolidated balance sheets.
The following table summarizes the notional volumes of derivatives used for hedging and trading activities:
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The following table summarizes the fair value of derivative instruments reflected on EMG's consolidated balance sheets:
Cash flow hedges
Trading activities
Netting and collateral received1
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The following table provides the activity of accumulated other comprehensive income, containing information about the changes in the fair value of cash flow hedges, to the extent effective, and reclassification from accumulated other comprehensive income into results of operations:
Accumulated other comprehensive income derivative gain at January 1
Effective portion of changes in fair value
Reclassification from accumulated other comprehensive income to net income
Accumulated other comprehensive income derivative gain at March 31
For additional information related to accumulated other comprehensive income, see Note 11.
The portion of a cash flow hedge that does not offset the change in the value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EMG recorded net gains of $2 million and $9 million during the first quarters of 2011 and 2010, respectively, in competitive power generation revenues on the consolidated statements of income representing the amount of cash flow hedge ineffectiveness.
The effect of realized and unrealized gains (losses) from derivative instruments used for economic hedging and trading purposes on the consolidated statements of income is presented below:
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Contingent Features
Certain derivative instruments contain margin and collateral deposit requirements. Since EMG's credit ratings are below investment grade, EMG has provided collateral in the form of cash and letters of credit for the benefit of derivative counterparties. The aggregate fair value of all derivative instruments with credit-risk-related contingent features was in an asset position at March 31, 2011 and, accordingly, the contingent features described below do not currently have liquidity exposure. Certain derivative contracts do not require margin, but contain provisions that require EMG or Midwest Generation to comply with the terms and conditions of their respective credit facilities. The credit facilities each contain financial covenants. Some hedge contracts include provisions related to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. Failure by EMG or Midwest Generation to comply with these provisions may result in a termination event under the hedge contracts, enabling the counterparties to terminate and liquidate all outstanding transactions and demand immediate payment of amounts owed to them. EMMT has hedge contracts that do not require margin, but provide that each party can request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party. Future increases in power prices could expose EMG, Midwest Generation or EMMT to termination payments or additional collateral postings under the contingent features described above.
Margin and collateral deposits include cash deposited with counterparties and brokers, and cash received from counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the fair value of the related positions. Edison International nets counterparty receivables and payables where balances exist under master netting agreements. Edison International presents the portion of its margin and collateral deposits netted with its derivative positions on its consolidated balance sheets. The following table summarizes margin and collateral deposits provided to and received from counterparties:
Collateral provided to counterparties:
Offset against derivative liabilities
Reflected in margin and collateral deposits
Collateral received from counterparties:
Offset against derivative assets
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Effective Tax Rate
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision from continuing operations.
Provision for income tax at federal statutory rate of 35%
Increase (decrease) in income tax from:
State tax – net of federal benefit
Health care legislation1
Production and housing credits
Property-related and other
Total income tax expense from continuing operations
Effective tax rate
The CPUC requires flow-through ratemaking treatment for the current tax benefit arising from certain property-related and other temporary differences which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense.
Accounting for Uncertainty in Income Taxes
Authoritative guidance related to accounting for uncertainty in income taxes requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. The guidance requires the disclosure of all unrecognized tax benefits, which includes both the reserves recorded for tax positions on filed tax returns and the unrecognized portion of affirmative claims.
Unrecognized Tax Benefits
The following table provides a reconciliation of unrecognized tax benefits:
Balance at January 1,
Tax positions taken during the current year:
Increases
Tax positions taken during a prior year:
Decreases
Balance at March 31,
As of March 31, 2011 and December 31, 2010, respectively, if recognized, $460 million and $455 million of the unrecognized tax benefits would impact the effective tax rate.
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Edison International's federal income tax returns and its California combined franchise tax returns are currently open for years subsequent to 2002. In addition, specific California refund claims made by Edison International for years 1991 through 2002 are currently under review by the Franchise Tax Board. The IRS examination phase of tax years 2003 through 2006 was completed in the fourth quarter of 2010, which included proposed adjustments for the following two items:
Edison International disagrees with the proposed adjustments and filed a protest with the IRS in the first quarter of 2011.
Accrued Interest and Penalties
The total amount of accrued interest and penalties related to Edison International's income tax liabilities was $217 million and $213 million as of March 31, 2011 and December 31, 2010, respectively.
The net after-tax interest and penalties recognized in income tax expense was $3 million and $15 million for the three months ended March 31, 2011 and 2010, respectively.
Pension Plans and Postretirement Benefits Other Than Pensions
Pension Plans
During the three months ended March 31, 2011, Edison International made 2010 plan year contributions of $2 million, 2011 plan year contributions of $28 million and expects to make $4 million of additional 2010 plan year contributions and $96 million of additional 2011 plan year contributions during the remainder of 2011. Annual contributions made to most of SCE's pension plans are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the annual expense.
Expense components are:
Service cost
Interest cost
Expected return on plan assets
Amortization of prior service cost
Amortization of net loss
Expense under accounting standards
Regulatory adjustment – deferred
Total expense recognized
Postretirement Benefits Other Than Pensions
During the three months ended March 31, 2011, Edison International made 2011 plan year contributions of $6 million and expects to make $50 million of additional contributions during the remainder of 2011. Annual contributions made to SCE plans are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the annual expense.
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Amortization of prior service cost (credit)
Total expense
Stock-Based Compensation
During the first quarter of 2011, Edison International granted its 2011 stock-based compensation awards, which included stock options, performance shares and restricted stock units.
Stock Options
The following is a summary of the status of Edison International stock options:
Outstanding at December 31, 2010
Granted
Expired
Forfeited
Exercised
Outstanding at March 31, 2011
Vested and expected to vest at March 31, 2011
Exercisable at March 31, 2011
At March 31, 2011, there was $32 million of total unrecognized compensation cost related to stock options, net of expected forfeitures. That cost is expected to be recognized over a weighted-average period of approximately three years.
Performance Shares
The following is a summary of the status of Edison International nonvested performance shares:
Nonvested at December 31, 2010
Nonvested at March 31, 2011
The current portion of nonvested performance shares classified as liability awards is reflected in "Other current liabilities" and the long-term portion is reflected in "Pensions and benefits" on the consolidated balance sheets.
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At March 31, 2011, there was $7 million (based on the March 31, 2011 fair value of performance shares classified as equity awards) of total unrecognized compensation cost related to performance shares. That cost is expected to be recognized over a weighted-average period of approximately two years.
Restricted Stock Units
The following is a summary of the status of Edison International nonvested restricted stock units granted to SCE employees:
Paid Out
At March 31, 2011, there was $14 million of total unrecognized compensation cost related to restricted stock units, net of expected forfeitures, which is expected to be recognized as follows: $6 million in 2011, $6 million in 2012 and $2 million in 2013.
Supplemental Data on Stock Based Compensation
Stock based compensation expense1
Income tax benefits related to stock compensation expense
Excess tax benefits2
Stock options
Cash used to purchase shares to settle options
Cash from participants to exercise stock options
Value of options exercised
Restricted stock units
Value of shares settled
Tax benefits realized from settlement of awards
No performance shares were settled as of March 31, 2011 and 2010, respectively.
Third-Party Power Purchase Agreements
During the first quarter of 2011, SCE entered into a renewable energy power purchase contract which is classified as an operating lease. SCE's additional commitments under this contract are estimated to be: $29 million each year in 2012 – 2015 and $468 million for the period remaining thereafter.
Other Commitments
At March 31, 2011, Midwest Generation and EMG Homer City Generation L.P. ("Homer City") had commitments to purchase coal from third-party suppliers at fixed prices, subject to adjustment clauses.
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These commitments are estimated to aggregate $677 million, summarized as follows: $373 million for the remainder of 2011, $255 million in 2012 and $49 million in 2013.
Turbine Commitments
At March 31, 2011, EMG had commitments to purchase wind turbines of $90 million due in 2011. EMG's failure to schedule turbine delivery by June 2011 would result in a termination obligation equal to its turbine deposit, which would result in a $21 million charge against earnings. EMG has identified a project in which to place these turbines. However, there is no assurance that development will be completed and the turbines will be used for this project.
On October 8, 2010, an agreement was reached to settle disputes included in the complaint filed by EMG against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd. with respect to a wind turbine generator supply agreement. As a result of this agreement, EMG may elect to deploy up to 60 additional wind turbines (aggregating 144 MW) that were part of the original contract, or may be obligated to make a payment of up to $30 million following the end of the three-year period if it has not elected to deploy the additional turbines and if certain other criteria apply. In April 2011, the 55 MW Pinnacle wind project in West Virginia, which will deploy the 23 wind turbines purchased from Mitsubishi, commenced construction.
Capital Expenditures
At March 31, 2011, EMG's subsidiaries had firm commitments to spend approximately $153 million during the remainder of 2011 on capital and construction expenditures. These expenditures primarily relate to selective non-catalytic reduction ("SNCR") equipment at the Midwest Generation plants, the construction of wind projects and non-environmental improvements at the coal plants. EMG intends to fund these expenditures through project level and turbine vendor financing, U.S. Treasury grants, cash on hand and cash generated from operations.
Guarantees and Indemnities
Edison International's subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts included performance guarantees and indemnifications.
Environmental Indemnities Related to the Midwest Generation Plants
In connection with the acquisition of the Midwest Generation plants, EME agreed to indemnify Commonwealth Edison Company ("Commonwealth Edison") with respect to specified environmental liabilities before and after December 15, 1999, the date of sale. The indemnification claims are reduced by any insurance proceeds and tax benefits related to such claims and are subject to a requirement that Commonwealth Edison takes all reasonable steps to mitigate losses related to any such indemnification claim. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. Also, in connection with the sale-leaseback transaction related to the Powerton and Joliet Stations in Illinois, EME agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligations under these indemnities, a maximum potential liability cannot be determined. Commonwealth Edison has advised EME that Commonwealth Edison believes it is entitled to indemnification for all liabilities, costs, and expenses that it may be required to bear as a result of the litigation discussed below under "—Contingencies—Midwest Generation New Source Review Lawsuit." Except as discussed below, EME has not recorded a liability related to these environmental indemnities.
Midwest Generation entered into a supplemental agreement with Commonwealth Edison and Exelon Generation Company LLC on February 20, 2003 to resolve a dispute regarding interpretation of its reimbursement obligation for asbestos claims under the environmental indemnities set forth in the Asset Sale Agreement. Under this supplemental agreement, Midwest Generation agreed to reimburse Commonwealth Edison and Exelon Generation for 50% of specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs, and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement. As a general matter, Commonwealth Edison and Midwest Generation apportion responsibility for future
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asbestos-related claims based upon the number of exposure sites that are Commonwealth Edison locations or Midwest Generation locations. The obligations under this agreement are not subject to a maximum liability. The supplemental agreement had an initial five-year term with an automatic renewal provision for subsequent one-year terms (subject to the right of either party to terminate); pursuant to the automatic renewal provision, it has been extended until February 2012. There were approximately 228 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at March 31, 2011. Midwest Generation had recorded a liability of $56 million at March 31, 2011 related to this contract indemnity.
The amounts recorded by Midwest Generation for the asbestos-related liability are based upon a number of assumptions. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding asbestos litigation in the United States, could cause the actual costs to be higher or lower than projected.
Environmental Indemnity Related to the Homer City Plant
In connection with the acquisition of the Homer City plant, Homer City agreed to indemnify the sellers with respect to specified environmental liabilities before and after the date of sale. Payments would be triggered under this indemnity by a valid claim from the sellers. EME guaranteed this obligation of Homer City. Also, in connection with the sale-leaseback transaction related to the Homer City plant, Homer City agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligations under these indemnity provisions, they are not subject to a maximum potential liability and do not have expiration dates. For discussion of the New Source Review lawsuit filed against Homer City, see "—Contingencies—Homer City New Source Review Lawsuit." EME has not recorded a liability related to this indemnity.
Indemnities Provided under Asset Sale and Sale-Leaseback Agreements
The asset sale agreements for the sale of EME's international assets contain indemnities from EME to the purchasers, including indemnification for taxes imposed with respect to operations of the assets prior to the sale and for pre-closing environmental liabilities. Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. At March 31, 2011, EME had recorded a liability of $44 million related to these matters.
In connection with the sale of various domestic assets, EME has from time to time provided indemnities to the purchasers for taxes imposed with respect to operations of the assets prior to the sale. EME has also provided indemnities to purchasers for items specified in each agreement (for example, specific pre-existing litigation matters and/or environmental conditions). Due to the nature of the obligations under these indemnity agreements, a maximum potential liability cannot be determined.
Not all indemnities under the asset sale agreements have specific expiration dates. Payments would be triggered under these indemnities by valid claims from the sellers or purchasers, as the case may be. No significant amounts are recorded as a liability for these matters.
In connection with the sale-leaseback transactions related to the Homer City plant in Pennsylvania, the Powerton and Joliet Stations in Illinois and, previously, the Collins Station in Illinois, EME and several of its subsidiaries entered into tax indemnity agreements. Although the Collins Station lease terminated in April 2004, Midwest Generation's tax indemnity agreement with the former lease equity investor is still in effect. Under these tax indemnity agreements, these entities agreed to indemnify the lessors in the sale-leaseback transactions for specified adverse tax consequences that could result in certain situations set forth in each tax indemnity agreement, including specified defaults under the respective leases. The potential indemnity obligations under these tax indemnity agreements could be significant. Due to the nature of these potential obligations, EME cannot determine a maximum potential liability which would be triggered by a valid claim from the lessors. No significant amounts are recorded as a liability for these matters.
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Indemnity Provided as Part of the Acquisition of Mountainview
In connection with the acquisition of the Mountainview power plant, SCE agreed to indemnify the seller with respect to specific environmental claims related to SCE's previously owned San Bernardino Generating Station, divested by SCE in 1998 and reacquired as part of the Mountainview acquisition. SCE retained certain responsibilities with respect to environmental claims as part of the original divestiture of the station. The aggregate liability for either party to the purchase agreement for damages and other amounts is a maximum of $60 million. This indemnification for environmental liabilities expires on or before March 12, 2033. SCE has not recorded a liability related to this indemnity.
Mountainview Filter Cake Indemnity
The Mountainview power plant utilizes water from on-site groundwater wells and City of Redlands ("City") recycled water for cooling purposes. Unrelated to the operation of the plant, the groundwater contains perchlorate. The pumping of the water removes perchlorate from the aquifer beneath the plant and concentrates it in the plant's wastewater treatment "filter cake." Use of this impacted groundwater for cooling purposes was mandated by Mountainview's California Energy Commission permit. SCE has indemnified the City for cleanup or associated actions related to groundwater contaminated by perchlorate due to the disposal of filter cake at the City's solid waste landfill. The obligations under this agreement are not limited to a specific time period or subject to a maximum liability. SCE has not recorded a liability related to this indemnity.
Other Edison International Indemnities
Edison International provides other indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and specified environmental indemnities and income taxes with respect to assets sold. Edison International's obligations under these agreements may be limited in terms of time and/or amount, and in some instances Edison International may have recourse against third parties for certain indemnities. The obligated amounts of these indemnifications often are not explicitly stated, and the overall maximum amount of the obligation under these indemnifications cannot be reasonably estimated. Edison International has not recorded a liability related to these indemnities.
In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International believes the outcome of these other proceedings will not materially affect its results of operations or liquidity.
In August 2009, the United States Environmental Protection Agency ("US EPA") and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, alleging that Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration ("PSD") requirements and of the New Source Performance Standards of the Clean Air Act ("CAA"), including alleged requirements to obtain a construction permit and to install controls sufficient to meet best available control technology ("BACT") emissions rates. The US EPA also alleged that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the CAA. Finally, the US EPA alleged violations of certain opacity and particulate matter standards at the Midwest Generation plants. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint calls for an injunction ordering Midwest Generation to install controls sufficient to meet BACT emissions rates at all units subject to the complaint; to obtain new PSD or New Source Review permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. The remedies sought by the plaintiffs in the lawsuit could go well beyond the requirements of the Combined Pollutant Standard ("CPS"). Several Chicago-based environmental action groups have intervened in the case.
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In March 2010, nine of the ten counts related to PSD requirements in the complaint were dismissed, and the tenth count was also dismissed to the extent it sought civil penalties under the CAA, as barred by the applicable statute of limitations. Following those dismissals, the government plaintiffs filed an amended complaint, with claims that attempted to add Commonwealth Edison and EME as defendants and introduce new legal theories to impose liability on Midwest Generation and EME. In March 2011, the court again dismissed the nine PSD claims previously dismissed in 2010, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The court also dismissed all claims asserted against Commonwealth Edison and EME. The court denied a motion to dismiss a claim by the Chicago-based environmental action groups for civil penalties in the remaining PSD claim, but noted that the plaintiffs will be required to convince the court that the statute of limitations should be equitably tolled. The court did not address other counts in the complaint that allege violations of opacity and particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA. Trial of the liability portion of the case is scheduled to commence June 3, 2013.
An adverse decision could involve penalties and remedial actions that could have a material adverse impact on the financial condition and results of operations of Midwest Generation and EME. EME cannot predict the outcome of these matters or estimate the impact on the Midwest Generation plants, or its and Midwest Generation's results of operations, financial position or cash flows.
In January 2011, the US EPA filed a complaint in the Western District of Pennsylvania against Homer City, the sale-leaseback owner participants of the Homer City plant, and two prior owners of the Homer City plant. The complaint alleges violations of the PSD and Title V provisions of the CAA and its implementing regulations, including requirements contained in the Pennsylvania State Implementation Plan, as a result of projects in the 1990s performed by prior owners without PSD permits and the subsequent failure to incorporate emissions limitations that meet BACT into the station's Title V operating permit. In addition to seeking penalties ranging from $32,500 to $37,500 per violation, per day, the complaint calls for an injunction ordering Homer City to install controls sufficient to meet BACT emissions rates at all units subject to the complaint; to obtain new PSD or New Source Review permits for those units; to amend its applications under Title V of the CAA; to conduct audits of its operations to determine whether any additional modifications have occurred; and to offset and mitigate the harm to public health and the environment caused by the alleged CAA violations. Pennsylvania Department of Environmental Protection, the State of New York and the State of New Jersey have intervened in the lawsuit.
Also in January 2011, two residents filed a complaint in the Western District of Pennsylvania, on behalf of themselves and all others similarly situated, against Homer City, the sale-leaseback owner participants of the Homer City plant, two prior owners of the Homer City plant, EME, and Edison International, claiming that emissions from the Homer City plant had adversely affected their health and property values. The plaintiffs seek to have their suit certified as a class action and request injunctive relief, the funding of a health assessment study and medical monitoring, compensatory and punitive damages.
In April 2011, Homer City filed motions to dismiss both complaints. An adverse decision could involve penalties, remedial actions and damages that could have a material adverse impact on the financial condition and results of operations of Homer City and EME. EME cannot predict the outcome of these matters or estimate the impact on the Homer City plant, or its and Homer City's results of operations, financial position or cash flows.
Navajo Nation Litigation
The Navajo Nation filed a complaint in June 1999 against SCE, among other defendants, arising out of the coal supply agreement for Mohave. Subsequently, the Hopi Tribe was added as an additional plaintiff. As amended in April 2010, the Navajo Nation's complaint asserts claims for, among other things, interference with fiduciary duties and contractual relations, fraudulent misrepresentations by nondisclosure, and various contract-related claims. The complaint claims that the defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal supplied to Mohave. The complaint seeks damages of not less than $600 million, plus interest thereon, and punitive damages of not less than $1 billion. No trial date has been set for this litigation. In April 2009, in a related case filed in December 1993 against the U.S. Government, the U.S. Supreme Court found that the Navajo Nation did not have a claim for compensation. In October 2010, the Hopi Tribe settled all of its claims and the remaining parties
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agreed to engage in mediation. SCE cannot predict the outcome of the Navajo Nation's complaint against SCE.
Edison International records its environmental remediation liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. Edison International reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure. Unless there is a probable amount, Edison International records the lower end of this reasonably likely range of costs (reflected in "Other long-term liabilities") at undiscounted amounts as timing of cash flows is uncertain.
As of March 31, 2011, Edison International's recorded estimated minimum liability to remediate its 29 identified material sites (sites in which the upper end of the range of costs is at least $1 million) at SCE (24 sites) and EMG (5 sites primarily related to Midwest Generation) was $59 million, of which $52 million was related to SCE, including $20 million related to San Onofre. In addition to its identified material sites, SCE also has 33 immaterial sites for which the total minimum recorded liability was $3 million. Edison International's other subsidiaries have no identified remediation sites. The ultimate costs to clean up Edison International's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. Edison International believes that, due to these uncertainties, it is reasonably possible that cleanup costs at these identified material sites and immaterial sites could exceed its recorded liability by up to $190 million and $7 million, respectively, all of which is related to SCE. The upper limit of this range of costs was estimated using assumptions least favorable to Edison International among a range of reasonably possible outcomes.
The CPUC allows SCE to recover 90% of its environmental remediation costs at certain sites, representing $28 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE recovers 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $52 million at March 31, 2011 for its estimated minimum environmental cleanup costs expected to be recovered through customer rates.
Edison International's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that Edison International may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $3 million to $18 million. Recorded costs were $4 million and less than $1 million for the three months ended March 31, 2011 and 2010, respectively.
Based on currently available information, Edison International believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of environmental remediation costs incurred at SCE, Edison International believes that costs ultimately recorded will not materially affect its results of operations, financial position or cash flows. There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.
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Nuclear Insurance
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 San Onofre and Palo Verde have purchased the maximum private primary insurance available ($375 million). The balance is covered by a loss sharing program among nuclear reactor licensees. If a nuclear incident at any licensed reactor in the United States results in claims and/or costs which exceed the primary insurance at that plant site, all nuclear reactor licensees could be required to contribute their share of the liability in the form of a deferred premium.
Based on its ownership interests, SCE could be required to pay a maximum of approximately $235 million per nuclear incident. However, it would have to pay no more than approximately $35 million per incident in any one year. If the public liability limit above is insufficient, federal law contemplates that additional funds may be appropriated by Congress. This could include an additional assessment on all licensed reactor operators as a measure for raising further federal revenue.
Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by entities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $48 million per year. Insurance premiums are charged to operating expense.
Spent Nuclear Fuel
Under federal law, the Department of Energy ("DOE") is responsible for the selection and construction of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not meet its contractual obligation to begin acceptance of spent nuclear fuel by January 31, 1998. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. Currently, both San Onofre and Palo Verde have interim storage for spent nuclear fuel on site sufficient for the current license period.
In January 2004, SCE, as operating agent of San Onofre, filed a complaint against the DOE in the United States Court of Federal Claims seeking damages for the DOE's failure to meet its obligation to begin accepting spent nuclear fuel from San Onofre. In June 2010, the United States Court of Federal Claims issued a decision granting SCE damages of approximately $142 million to recover costs incurred through December 31, 2005, which has been appealed by the DOE. Additional legal action would be necessary to recover damages incurred after that date. Any damages recovered would be returned to SCE ratepayers or used to offset past or future fuel decommissioning or storage costs for the benefit of ratepayers.
Environmental Developments
Greenhouse Gas Regulation
In March 2011, a California court issued an order suspending CARB's regulations implementing a California cap-and-trade program. The order would also potentially apply to other measures included in the regulations. The CARB has the right to appeal the ruling.
In April 2011, California enacted a law requiring that California utilities purchase 33% of their electricity requirements from renewable resources. The law requires the CPUC to adopt implementing regulations. The impact of the new 33% law will depend on the content of yet to be adopted implementing regulations, which remains uncertain.
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Hazardous Air Pollutant Regulations
In March 2011, the US EPA issued draft "National Emission Standards for Hazardous Air Pollutants," limiting emissions of hazardous air pollutants ("HAPs") from coal- and oil-fired electrical generating units. The regulations are expected to be finalized by November 2011. Based on its continuing review, EMG does not expect these standards, if adopted, would require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. Midwest Generation expects to continue to develop and implement a compliance program that includes the use of activated carbon injection, upgrades to particulate removal systems and dry sorbent injection, combined with its use of low sulfur Powder River Basin ("PRB") coal, to meet emission limits for criteria pollutants, such as nitrogen oxide ("NOx") and sulfur dioxide ("SO2") as well as for HAPs, such as mercury, acid gas and non-mercury metals. With respect to the Homer City plant, the proposed standards, like the pending Clean Air Transport Rule, will require additional reductions in and controls for SO2 emissions.
Water Quality
Once-Through Cooling Issues
In March 2011, the US EPA proposed draft standards under the federal Clean Water Act which 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. Edison International is still evaluating the proposed standards but believes, from a preliminary review, that compliance with the proposed standards regarding impingement will be achievable without incurring material additional capital expenditures or operating costs for both the Midwest Generation plants and the Homer City plant. 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.
In addition to the proposed draft US EPA standards, the existing California once-through cooling policy may result in significant capital expenditures at San Onofre and may affect its operations. The California policy may also significantly impact SCE's ability to procure generating capacity from fossil-fueled plants that use ocean water in once-through cooling systems, system reliability and the cost of electricity if other coastal power plants in California are forced to shut down or limit operations.
Note 11. Accumulated Other Comprehensive Loss
Edison International's accumulated other comprehensive loss consists of:
Current period change
Included in accumulated other comprehensive loss at March 31, 2011 was $21 million, net of tax, of unrealized gains on commodity-based cash flow hedges; and $9 million, net of tax, of unrealized losses related to interest rate hedges. The maximum period over which a commodity cash flow hedge is designated is May 31, 2014.
Unrealized gains on commodity hedges consist of futures and forward electricity contracts that qualify for hedge accounting. These gains arise because current forecasts of future electricity prices in these markets are lower than the contract prices. Approximately $21 million of unrealized gains on cash flow hedges, net of tax, are expected to be reclassified into earnings during the next 12 months. Management expects that
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reclassification of net unrealized gains will increase energy revenues recognized at market prices. Actual amounts ultimately reclassified into earnings over the next 12 months could vary materially from this estimated amount as a result of changes in market conditions.
Edison International's supplemental cash flows information is:
Cash payments (receipts) for interest and taxes:
Interest – net of amounts capitalized
Tax payments (refunds) – net
Noncash investing and financing activities:
Accrued capital expenditures
Consolidation of variable interest entities:
Assets other than cash
Liabilities and noncontrolling interests
Deconsolidation of variable interest entities:
Dividends declared but not paid:
Common stock
In March 2011, SCE issued 1,250,000 shares of 6.5% Series D preference stock (cumulative, $100 liquidation value). The Series D preference stock may not be redeemed prior to March 1, 2016. After March 1, 2016, SCE may, at its option, redeem the shares, in whole or in part. These shares are not subject to mandatory redemption.
Regulatory assets included on the consolidated balance sheets are:
Current:
Regulatory balancing accounts
Energy derivatives
Long-term:
Deferred income taxes – net
Pensions and other postretirement benefits
Unamortized generation investment – net
Unamortized loss on reacquired debt
Nuclear-related ARO investment – net
Unamortized distribution investment – net
Total Regulatory Assets
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Regulatory liabilities included on the consolidated balance sheets are:
Costs of removal
ARO
Total Regulatory Liabilities
Future nuclear decommissioning costs of removal of nuclear assets are expected to be funded from independent decommissioning trusts, which currently receive contributions of approximately $23 million per year included in SCE customer rates. Contributions to the decommissioning trusts are reviewed every three years by the CPUC. If additional funds are needed for decommissioning, it is probable that the additional funds will be recoverable through customer rates. Funds collected, together with accumulated earnings, will be utilized solely for decommissioning. The CPUC has set certain restrictions related to the investments of these trusts.
The following table sets forth amortized cost and fair value of the trust investments:
Stocks
Corporate bonds
Short-term investments and receivables/payables
Trust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Proceeds from sales of securities (which are reinvested) were $622 million and $286 million for the three months ended March 31, 2011 and 2010, respectively. Unrealized holding gains, net of losses, were $1.4 billion and $1.3 billion at March 31, 2011 and December 31, 2010, respectively. Approximately 92% of the cumulative trust fund contributions were tax-deductible.
The following table sets forth a summary of changes in the fair value of the trust:
Realized gains – net
Unrealized gains – net
Other-than-temporary impairments
Interest, dividends, contributions and other
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Due to regulatory mechanisms, earnings and realized gains and losses (including other-than-temporary impairments) have no impact on operating revenue or earnings.
Other income and expenses are as follows:
Other income:
Equity AFUDC
Increase in cash surrender value of life insurance policies
Total utility other income
Competitive power generation and other income
Total other income
Other expenses:
Civic, political and related activities and donations
Total utility other expenses
Competitive power generation and other expenses
Total other expenses
Edison International has two business segments for financial reporting purposes: an electric utility operation segment (SCE) and a competitive power generation segment (EMG). The significant accounting policies of the segments are the same as those described in Note 1.
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Reportable Segments Information
The following is information (including the elimination of intercompany transactions) related to Edison International's reportable segments:
Operating Revenue:
Parent and other2
Consolidated Edison International
Net Income (Loss) attributable to Edison International:
Competitive power generation1
Segment balance sheet information was:
Total Assets:
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This quarterly report on Form 10-Q 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:
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Additional information about risks and uncertainties, including more detail about the factors described above, is contained throughout this MD&A and in Edison International's 2010 Form 10-K, including the "Risk Factors" section in Part I, Item 1A. Readers are urged to read this entire report, including the information incorporated by reference, as well as the 2010 Form 10-K, 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.
This MD&A for the three months ended March 31, 2011 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International since December 31, 2010, and as compared to the three months ended March 31, 2010. This discussion presumes that the reader has read or has access to Edison International's MD&A for the calendar year 2010 (the "year-ended 2010 MD&A"), which was included in the 2010 Form 10-K.
Net Income (Loss) Attributable to Edison International
SCE
EMG
Edison International Parent and Other
Edison International Consolidated
Non-Core Items
SCE – tax impact of health care legislation
EMG discontinued operations
Total non-core items
Core Earnings (Losses)
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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 are a non-GAAP financial measure and may not be comparable to those of other companies. Core earnings are defined as earnings attributable to Edison International shareholders less income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: 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 $19 million primarily due to rate base growth.
EMG's 2011 core earnings decreased $89 million primarily due to unplanned outages at Homer City, lower energy prices, distributions from EMG's Doga and March Point projects during 2010 (none received in 2011) and lower trading revenue.
Consolidated non-core items for Edison International included 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.
During the first quarter, SCE's capital investment program focused on upgrading, maintaining and expanding SCE's transmission and distribution system; maintaining and replacing generation asset equipment; and installing smart meters. Total capital expenditures (including accruals) were $765 million during the first quarter of 2011 compared to $640 million during the same period in 2010.
SCE continues to project that 2011 capital investments will be in the range of $3.9 billion to $4.4 billion and that 2011 – 2014 total capital investment spending will be in the range of $15.6 billion to $17.5 billion. Actual capital spending will be affected by regulatory approval, permitting, market and other factors as discussed further under "SCE: Liquidity and Capital Resources—Capital Investment Plan" in the year-ended 2010 MD&A.
As discussed in the year-ended 2010 MD&A, SCE is required to update its 2012 GRC application to reflect, among other things, the impacts of governmental and legislative actions. In April 2011, the IRS issued guidance for determining bonus depreciation enacted in the 2010 Tax Relief Act. On April 28, 2011, SCE submitted an update of its 2012 GRC application primarily to reflect bonus depreciation deductions under the 2010 Tax Relief Act, reducing its base rate revenue requirement by $38 million, $133 million and $145 million in 2012, 2013 and 2014, respectively. The decrease in base rate revenue requirement is due to a reduction in rate base from inclusion of higher deferred income taxes resulting from bonus depreciation. SCE's revised request, after considering the effects of sales growth, would result in incremental customer rate increases of $828 million, $152 million and $514 million in 2012, 2013 and 2014, respectively.
The current schedule anticipates a final decision on SCE's 2012 GRC by the end of 2011. To the extent a final decision is delayed, the CPUC has authorized the establishment of a GRC memorandum account, which will make the revenue requirement ultimately adopted by the CPUC effective as of January 1, 2012.
As discussed in the 2010 Form 10-K under the heading "Nuclear Power Plant Regulation," SCE is subject to the jurisdiction of the NRC with respect to its ownership interest in San Onofre and Palo Verde. In light of the significant safety events at the Fukushima Daiichi nuclear plant in Japan resulting from the recent earthquake and tsunami, the NRC plans to perform additional operational and safety reviews of nuclear
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facilities in the United States. The lessons learned from the Japanese events and NRC reviews may impact future operations and capital requirements at United States nuclear facilities, including the operations and capital requirements of SCE's nuclear facilities.
The profitability of EMG's competitive power generation operations is expected to be significantly lower in 2011 as a result of lower realized energy prices driven by the expiration of hedge contracts, higher fuel costs and unplanned outages at the Homer City plant during the first quarter. In addition, the profitability of EME's Midwest Generation plants is expected to be adversely affected in 2012 by a decline in capacity prices (projected to begin in June 2012) and higher rail transportation costs (due to the expiration at the end of 2011 of a favorable long-term rail contract). As a result, EMG may incur net losses during 2011 and in subsequent years unless energy prices recover or its costs decline.
At March 31, 2011, EMG and its subsidiaries had $1.2 billion in cash and cash equivalents and $981 million of liquidity available from credit facilities that expire in 2012. EMG's principal subsidiary, EME, had $3.7 billion of senior notes outstanding at March 31, 2011, $500 million of which mature in 2013. EMG's business plans are focused on operating effectively through the current commodity price cycle and on environmental compliance and renewable energy plans as described below.
During the first quarter of 2011, Midwest Generation continued its permitting and planning activities for NOx and SO2controls to meet the requirements of the CPS. In February 2011, the Illinois Environmental Protection Agency issued construction permits authorizing Midwest Generation to install a dry sorbent injection system using Trona or other sodium-based sorbents at the Powerton Station's Units 5 and 6.
Decisions regarding whether or not to proceed with retrofitting units to comply with CPS requirements for SO2 emissions remain subject to a number of factors, such as market conditions, regulatory and legislative developments, and forecasted commodity prices and capital and operating costs applicable at the time decisions are required or made. Midwest Generation could also elect to temporarily or permanently shut down units, instead of installing controls, to be in compliance with the CPS.
Therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ also remain subject to conditions applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation intends to defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital that is budgeted may not occur until 2012 for some of the units and potentially later for others.
In March 2011, the US EPA issued draft "National Emission Standards for Hazardous Air Pollutants," limiting emissions of HAPs from coal- and oil-fired electrical generating units. The regulations are expected to be finalized by November 2011. Based on its continuing review, EME does not expect these standards, if adopted, would require Midwest Generation to make material changes to the approach to compliance with state and federal environmental regulations that it contemplates for CPS compliance. Midwest Generation expects to continue to develop and implement a compliance program that includes the use of activated carbon injection, upgrades to particulate removal systems and 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 HAPs, such as mercury, acid gas and non-mercury metals.
On February 10, 2011, a steam pipe ruptured at Unit 1 of the Homer City plant, taking the unit off line. Homer City took Unit 2 off line, which has the same design and operating conditions, to further evaluate the equipment due to the risk of a similar failure. On April 5, 2011, Unit 1 returned to service after making needed repairs, including replacing all pipes similar to the ruptured pipe. Unit 2 is undergoing similar repairs and is expected to return to service in the second quarter of 2011.
The unplanned outages at Units 1 and 2 and the continuation of low power prices have impacted Homer City's liquidity. As a result, in order to have sufficient working capital available for operating expenses and
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to pay the equity portion of Homer City's rent payment that was due April 1, 2011 to the owner-lessors, Homer City had to defer certain fuel deliveries, arrange for accelerated payments by EMMT for future energy deliveries under an intercompany agreement in place between EMMT and Homer City, and draw $12 million from the $20 million equity rent reserve established under its sale-leaseback transaction documents. Homer City must restore the equity rent reserve account and continue to make equity rent payments in order to be entitled to make future distributions. The advance payments made and currently anticipated in April are expected to total approximately $30 million. It is currently anticipated that all such amounts will be applied against amounts invoiced by EMMT under an intercompany agreement within the next six months, but the actual rate at which such advance payments will be applied will depend upon prevailing power prices and other factors. To further stabilize Homer City's liquidity, effective April 1, 2011, EMMT assigned to Homer City the benefit of an arrangement that allows EMMT to deliver power into the NYISO from Homer City. Accordingly, effective April 1, 2011, these revenues will now be recorded as part of Homer City's revenues in lieu of their prior classification as EMMT trading revenues. EMMT realized trading revenues of $28 million under this arrangement in 2010.
The actions described above also resulted in Homer City being in compliance with the covenant requirements under the sale-leaseback documents at March 31, 2011. Under these documents, the rent payments are comprised of two components, a senior rent portion and an equity rent portion. The senior rent is used exclusively for debt service to the holders of the senior secured bonds issued in connection with the sale-leaseback transaction, while the equity rent is paid to the owner-lessors. In order to pay the equity portion of the rent, among other requirements, Homer City is required to 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).
For additional information, see "EMG: Liquidity and Capital Resources—Debt Covenants and Dividend Restrictions" and "Item 1A. Risk Factors—Risks Relating to EMG—Liquidity Risks" in the 2010 Form 10-K.
For a discussion of environmental regulation developments regarding Greenhouse Gas Regulation, Hazardous Air Pollutant Regulations and Once-Through Cooling Issues, see "Edison International Notes to Consolidated Financial Statements—Note 10. Regulatory and Environmental Developments."
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SCE's results of operations are derived mainly through two sources:
Utility earning activities include base rates that are designed to recover forecasted operation and maintenance costs, certain capital-related carrying costs, interest, taxes and a return, including the return on capital projects recovered through CPUC-authorized mechanisms outside the GRC process. Differences between authorized amounts and actual results impact earnings. Also, included in utility earning activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.
Utility cost-recovery activities include rates that provide for recovery (with no return), subject to reasonableness review, of fuel costs, purchased power costs, public purpose related-program costs (including energy efficiency and demand-side management programs), certain operation and maintenance expenses, and depreciation expense related to certain projects.
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.
Operating revenue
Fuel and purchased power
Property taxes and other
Net interest expense and other
Income before income taxes
Dividends on preferred and preference stock
Net income available for common stock
Core Earnings1
Non-Core Earnings:
Tax impact of health care legislation
Total SCE GAAP Earnings
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Utility earning activities were primarily affected by the following:
See "—Income Taxes" below for more information on lower income taxes during 2011 compared to the same period in 2010.
Utility cost-recovery activities were primarily affected by the following:
SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account over/undercollections) was $2.1 billion and $2.0 billion for the three months ended March 31, 2011 and 2010, respectively. The increase reflects a rate increase of $90 million and a sales volume increase of $30 million. The rate increase reflects higher system average rates for 2011 compared to the same period in 2010, primarily due to the implementation of rates authorized in the CPUC 2009 GRC decision and the 2010 FERC rate case. As a result of the CPUC-authorized decoupling mechanism, SCE does not bear the volumetric risk related to retail electricity sales (see "Item 1. Business—Southern California Edison Company—Overview of Ratemaking Mechanisms" in the 2010 Form 10-K).
SCE remits to CDWR and does not recognize as revenue the amounts that SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers, CDWR bond-related costs and a portion of direct access exit fees. The amounts collected and remitted to CDWR were $275 million and $296 million for the three months ended March 31, 2011 and 2010, respectively. The CDWR-related rates in 2011 continue to reflect an approximately $585 million refund of operating reserves that CDWR can release as their contracts terminate. Total customer rates are expected to increase as
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CDWR operating reserves are fully refunded. The power contracts that CDWR allocated to SCE will terminate by the end of 2011. SCE's revenue and related purchased power expense is expected to increase as these CDWR contracts are replaced by power purchase agreements entered into by SCE.
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision.
Total income tax expense
The decreased benefit provided by property-related and other items was primarily due to lower deductions for asset removal costs and internally developed software in the first quarter of 2011 compared to the respective period in 2010.
SCE's ability to operate its business, complete planned capital projects, and implement its business strategy are dependent upon its cash flow and access to the capital markets to finance its activities. SCE's overall cash flows fluctuate based on, among other things, its ability to recover its costs in a timely manner from its customers through regulated rates, changes in commodity prices and volumes, collateral requirements, dividend payments made to Edison International, and the outcome of tax and regulatory matters.
SCE expects to fund its continuing obligations, projected capital expenditures for 2011 and dividends to Edison International through cash and equivalents on hand, operating cash flows, tax benefits and capital market financings of debt and preferred equity, as needed. SCE also has availability under its credit facilities if additional funding and liquidity are necessary to meet operating and capital requirements.
As of March 31, 2011, SCE had approximately $53 million of cash and equivalents. SCE had two credit facilities: a $2.4 billion five-year credit facility that matures in February 2013, with four one-year options to extend by mutual consent, and a $500 million three-year credit facility that matures in March 2013.
Commitment
Outstanding borrowings supported by credit facilities
Outstanding letters of credit
Amount available
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SCE has a debt covenant in its credit facilities that limits its debt to total capitalization ratio to less than or equal to 0.65 to 1. At March 31, 2011, SCE's debt to total capitalization ratio was 0.46 to 1.
The CPUC regulates SCE's capital structure and limits the dividends it may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a common equity component of 48%. SCE may make distributions to Edison International as long as the common equity component of SCE's capital structure remains at or above the 48% authorized level on a 13-month weighted average basis. At March 31, 2011, SCE's 13-month weighted-average common equity component of total capitalization was 50.8% resulting in the capacity to pay $471 million in additional dividends.
During the first quarter of 2011, SCE made a $115 million dividend payment to its parent, Edison International. Future dividend amounts and timing of distributions are dependent upon several factors including the actual level of capital expenditures, operating cash flows and earnings.
Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. The table below provides the amount of collateral posted by SCE to its counterparties as well as the potential collateral that would be required as of March 31, 2011.
Collateral posted as of March 31, 20111
Incremental collateral requirements for power procurement contracts resulting from apotential downgrade of SCE's credit rating to below investment grade
Posted and potential collateral requirements for derivative instruments and power procurement contracts2
SCE is self-insured for workers compensation claims. SCE assesses workers compensation claims that have been asserted and those that have been incurred but not reported to determine the probable amount of losses that should be recorded. The Department of Industrial Relations for the State of California requires companies that are self-insured for workers compensation to post collateral (in the form of cash and/or letters of credits) based on the estimated workers' compensation liability if a company's bond rating were to fall below "B." As of March 31, 2011, if SCE's bond rating were to fall below a "B" rating, SCE would be required to post $209 million for its workers compensation self-insurance plan.
The table below sets forth condensed historical cash flow information for SCE.
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Net cash provided by operating activities increased $359 million in the first quarter of 2011 compared to the first quarter of 2010 primarily reflecting higher net tax receipts of $104 million in 2011 compared to 2010 related to accelerated depreciation benefits and net cash inflows related to balancing account over- and under-collections. The 2011 change was also due to the timing of cash receipts and disbursements related to working capital items.
Net cash provided by financing activities for the first quarter of 2011 was $190 million consisting of the following significant events:
Net cash provided by financing activities for the first quarter of 2010 was $305 million consisting of the following significant events:
Cash flows from investing activities are driven primarily by capital expenditures and funding of nuclear decommissioning trusts. Capital expenditures were $1.0 billion and $867 million for the three months ended March 31, 2011 and 2010, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $47 million and $49 million for the three months ended March 31, 2011 and 2010, respectively.
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For a discussion of power purchase commitments, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Third-Party Power Purchase Agreements."
SCE has contingencies related to the Navajo Nation Litigation, nuclear insurance and spent nuclear fuel, which are discussed in "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies."
As of March 31, 2011, SCE had 24 identified material sites for remediation and recorded an estimated minimum liability of $52 million. SCE expects to recover 90% of its remediation costs at certain sites. See "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies" for further discussion.
SCE's primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms. SCE uses derivative instruments, as appropriate, to manage its market risks. For a further discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate risk, see "Edison International Notes to Consolidated Financial Statements—Note 6. Derivative and Hedging Activities" and "Note 4. Fair Value Measurements" and see "SCE: Market Risk Exposures—Commodity Price Risk" in the year-ended 2010 MD&A.
The fair value of outstanding derivative instruments used at SCE to mitigate its exposure to commodity price risk was a net liability of $310 million and $207 million at March 31, 2011 and December 31, 2010, respectively. For further discussion of fair value measurements and the fair value hierarchy, see "Edison International Notes to Consolidated Financial Statements—Note 4. Fair Value Measurements."
Credit risk exposure from counterparties for power and gas trading activities is measured as the sum of net accounts receivable (accounts receivable less accounts payable) and the current fair value of net derivative assets (derivative assets less derivative liabilities) reflected on the consolidated balance sheets. SCE enters into master agreements which typically provide for a right of setoff. Accordingly, SCE's credit risk exposure from counterparties is based on a net exposure under these agreements. SCE manages the credit risk on the portfolio for both rated and non-rated counterparties based on credit ratings using published ratings of counterparties and other publicly disclosed information, such as financial statements, regulatory filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual agreements,
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including master netting agreements. As of March 31, 2011, the amount of balance sheet exposure as described above, by the credit ratings of SCE's counterparties, was as follows:
S&P Credit Rating1
A or higher
A-
Not rated3
The credit risk exposure set forth in the table above is composed of $7 million of net accounts receivable and $280 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.
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This section discusses operating results for the three months ended March 31, 2011 and 2010. EMG's continuing operations include the coal plants, renewable energy and gas-fired projects, energy trading, and gas-fired projects under contract, corporate interest expense and general and administrative expenses. EMG's discontinued operations include all international operations, except the Doga project.
The following table is a summary of competitive power generation results of operations for the periods indicated.
Competitive power generation operating revenue
Other operation and maintenance
Depreciation and amortization
Other income (expense), net
Income (loss) from continuing operations before income taxes
Income tax expense (benefit)
Income (loss) from continuing operations
Less: Net (income) attributable to noncontrolling interests
Net income (loss) available for common shareholder
Non-Core Earnings (Losses)
Discontinued Operations
Total EMG GAAP Earnings (Loss)
EMG's first quarter 2011 core earnings were lower than first quarter 2010 core earnings primarily due to the following pre-tax items:
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Adjusted Operating Income ("AOI")—Overview
The following section and table provide a summary of results of EMG's operating projects and corporate expenses for the three months ended March 31, 2011 and 2010, together with discussions of the contributions by specific projects and of other significant factors affecting these results.
The following table shows the adjusted operating income (loss) of EMG's projects:
Midwest Generation plants
Homer City plant1
Energy trading1
Big 4 projects
Sunrise
Doga
March Point2
Westside projects
Other projects
Leveraged lease income
Other operating income (expense)
Corporate administrative and general
Corporate depreciation and amortization
AOI3
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The following table reconciles AOI to operating income as reflected on EMG's consolidated statements of income (loss):
AOI
Less:
Equity in income (loss) of unconsolidated affiliates
Dividend income from projects
Production tax credits
Other income, net
Operating Income
The following table presents additional data for the Midwest Generation plants:
Operating Revenue
Operating Expenses
Fuel1
Plant operations
Plant operating leases
Administrative and general
Other Income
Statistics
Generation (in GWh)
AOI from the Midwest Generation plants decreased $32 million for the first quarter of 2011, compared to the first quarter of 2010. The 2011 decrease in AOI was attributable to lower energy revenues and higher plant operations costs, partially offset by higher capacity revenues. The decline in energy revenues was due to lower average realized energy prices and lower generation primarily related to the permanent shutdown of Will County Units 1 and 2 at the end of 2010 in accordance with the CPS.
Included in operating revenues were unrealized gains of none and $7 million for the first quarters of 2011 and 2010, respectively. Unrealized gains in 2010 were attributable to both economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the consolidated statements of operations and the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. The ineffective portion of hedge contracts at the Midwest Generation plants was
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attributable to changes in the difference between energy prices at the Northern Illinois Hub (the settlement point under forward contracts) and the energy prices at the Midwest Generation plants' busbars (the delivery point where power generated by the Midwest Generation plants is delivered into the transmission system).
Included in fuel costs were unrealized losses of $1 million and $5 million during the first quarters of 2011 and 2010, respectively, due to oil futures contracts that were accounted for as economic hedges. These contracts were entered into in 2010 and 2009 to hedge variable fuel oil components of rail transportation costs.
The following table presents additional data for the Homer City plant:
Operating Income (Loss)
AOI from the Homer City plant decreased $53 million for the first quarter of 2011, compared to the first quarter of 2010. The 2011 decrease in AOI was attributable to lower energy revenues, driven by lower generation, and higher plant maintenance costs from unplanned outages at Units 1 and 2, partially offset by lower fuel costs. The decline in fuel costs was primarily due to lower generation, partially offset by higher coal costs.
Included in operating revenues were unrealized gains (losses) from hedge activities of $2 million and $(2) million for the first quarters of 2011 and 2010, respectively. Unrealized gains (losses) were attributable to both economic hedge contracts that are accounted for at fair value with offsetting changes recorded on the statements of operations and the ineffective portion of forward and futures contracts which are derivatives that qualify as cash flow hedges. The ineffective portion of hedge contracts at Homer City was attributable to changes in the difference between energy prices at PJM West Hub (the settlement point under forward contracts) and the energy prices at the Homer City busbar (the delivery point where power generated by the Homer City plant is delivered into the transmission system).
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
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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 Affecting Sales from the Coal Plants."
The following table presents additional data for EMG's renewable energy projects:
Production Tax Credits
Equity in income (losses) from unconsolidated affiliates
AOI1
Generation (in GWh)2
AOI from renewable energy projects increased $11 million in the first quarter of 2011, compared to the first quarter of 2010. The 2011 increase was primarily due to projects that achieved commercial operation in late 2010 and 2011 and increased generation at other projects due to higher availability and favorable wind conditions.
EMG seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities primarily in those markets in which it is active as a result of its management of the merchant power plants of Midwest Generation and Homer City. EMMT trades power, fuel, coal, and transmission congestion primarily in the eastern U.S. power grid using products available over the counter, through exchanges, and from independent system operators.
AOI from energy trading activities decreased $32 million for the first quarter of 2011, compared to the first quarter of 2010. The 2011 decrease was primarily attributable to lower revenues from congestion and power trading, compared to higher revenue in the first quarter of 2010.
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March Point. During the first quarter of 2010, AOI from the March Point project was $17 million due to equity distributions received from the project. EMG subsequently sold its ownership interest in the March Point project to its partner at book value in February 2010.
Doga. During the first quarter of 2010, EMG received a distribution from the Doga project. EMG expects to receive a distribution from the Doga project during the second half of 2011. AOI is recognized when cash is distributed from the project as the Doga project is accounted for on the cost method.
Seasonality. 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.
Interest expense, net of capitalized interest
EME debt
Non-recourse debt
EMG's interest expense increased primarily due to higher debt balances for wind project financing, higher interest expense related to a loan amendment and lower capitalized interest. Capitalized interest for renewable energy projects under construction was $10 million for the first quarter of 2011, compared to $11 million for the first quarter of 2010.
The table below provides a reconciliation of income tax expense computed at the federal statutory income tax rate.
Provision (benefit) for income tax at federal statutory rate of 35%
Tax credits, net
Income from discontinued operations, net of tax, decreased $8 million for the first quarter of 2011, compared to the first quarter of 2010. The 2011 decrease was primarily due to the expiration of a contract indemnity during the first quarter of 2010 related to EMG's previous sale of international projects.
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The following table summarizes available liquidity at March 31, 2011:
EME as a holding company
EME subsidiaries without contractual dividend restrictions
EME corporate cash and cash equivalents
EME subsidiaries with contractual dividend restrictions
Midwest Generation1
Other EME subsidiaries
Other EMG subsidiaries
EME, as a holding company, does not directly own any revenue-producing generation facilities. EME relies on cash distributions and tax payments from its projects to meet its obligations, including debt service obligations on long-term debt. The timing and amount of distributions from EME's subsidiaries may be restricted. For further details, see "—Debt Covenants and Dividend Restrictions."
The following table summarizes the status of the EME and Midwest Generation credit facilities at March 31, 2011, which mature in June 2012:
Commitments
Outstanding borrowings
EME and Midwest Generation may seek to extend or replace credit facilities or retire them by other means. The terms and conditions of any refinancing could be substantially different than those in the current credit facilities. Senior notes in the principal amount of $500 million, which bear interest at 7.50% per annum, are due in June 2013. EME may also from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, open market purchases, privately negotiated transactions or otherwise, depending on prevailing market conditions, EME's liquidity requirements, contractual restrictions and other factors.
For additional discussion of liquidity and the impact of Homer City's outages, see "Edison International Management Overview—Management Overview of EMG."
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At March 31, 2011, forecasted capital expenditures through 2013 by EMG's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:
Plant capital expenditures
Environmental expenditures
Homer City Plant
Capital and construction expenditures
Turbine commitments
Other capital expenditures
Midwest Generation plants' environmental expenditures include $64 million for remaining expenditures in 2011 related to selective non-catalytic reduction (SNCR) equipment and $503 million for expenditures for the remainder of 2011 to 2013 to begin to retrofit initial units using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2 emissions. Midwest Generation could elect to shut down units instead of installing controls to be in compliance with the CPS, and, therefore, decisions about any particular combination of retrofits and shutdowns it may ultimately employ to comply remain subject to conditions applicable at the time decisions are required or made. Accordingly, the environmental expenditures for Midwest Generation in the preceding table represent current projects only and are subject to change based upon a number of considerations. Actual expenditures could be higher or lower. Preconstruction engineering and initial construction work for a project may occur in 2011 in advance of a final decision to continue or complete the project. For additional discussion, see "Edison International Management Overview—Management Overview of EMG—Midwest Generation Environmental Compliance Plans and Costs."
The capital investment plan set forth in the previous table does not include environmental capital expenditures for Homer City. However, depending on upcoming and future regulatory developments, Homer City may be required to undertake capital projects to install additional pollution control equipment, which will be dependent on lessor decisions and on obtaining available funding for these expenditures. Homer City projects that if SO2 reduction technology becomes required, it may need to make capital commitments for such equipment several years in advance of the effective date of such requirements. Homer City continues to review technologies available to reduce SO2 and mercury emissions and to monitor developments related to hazardous pollutants and other environmental regulations. The timing, selection of technology and required capital costs remain uncertain. Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction could affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures, and Homer City may need third-party capital to fund such activities in order to continue operating, the availability of which cannot be assured. EME has no legal obligation to provide funding. Accordingly, final decisions on whether to install controls, to install particular kinds of controls, and to actually expend capital have not been made. For a discussion of environmental regulations, refer to "Item 1. Environmental Regulation of Edison International and Subsidiaries" and refer to "Item 1A. Risk Factors—Risks Relating to EMG—Regulatory and Environmental Risks" in the 2010 Form 10-K.
Plant capital expenditures in the preceding table relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, generator stator rewinds, condenser
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re-tubing, development of a coal-cleaning plant refuse site and a new ash disposal site, and main power transformer replacement.
Renewable energy projects' capital and construction expenditures include a project of an unconsolidated entity in which construction expenditures will be substantially funded by EMG. In addition, U.S. Treasury grants of $367 million are anticipated based on estimated eligible construction costs for renewable projects completed in 2010 and scheduled to be completed in 2011.
The capital investment plan set forth in the previous table does not include capital expenditures for future projects. At March 31, 2011, EMG had a development pipeline of potential wind projects with projected installed capacity of approximately 3,700 MW. The development pipeline represents potential wind projects with respect to which EMG either owns the project rights or has exclusive acquisition rights. At March 31, 2011, EMG had two wind projects totaling 160 MW under construction. In April 2011, the 55 MW Pinnacle wind project in West Virginia commenced construction. EMG anticipates that these wind projects will achieve commercial operation in 2011. The pace of additional growth in EMG's renewable program will be subject to the availability of third-party equity capital. At March 31, 2011, EMG had capitalized costs and made turbine deposits totaling $45 million related to renewable energy development efforts. To the extent that the renewable energy projects are not successful, EMG would record a charge to write down the carrying amount of these assets.
During the first quarter, EMG entered into a memorandum of understanding with AES Southland Holdings, LLC to purchase certain equipment at AES's Huntington Beach facility and lease back such equipment until decommissioned. The transaction, if consummated, would result in retirement of the equipment in late 2012 in connection with the startup of EMG's proposed Walnut Creek natural gas-fired peaker plant, thereby exempting the proposed Walnut Creek plant from 90% of the regulatory requirement for emission reduction credits needed to start construction. In April 2011, EMG entered into turbine supply and construction agreements with limited contractual obligations until such time as the remaining development activities, including final permitting, are completed. EMG intends to obtain project debt financing for this 479 MW project, which has a long-term power sales agreement with Southern California Edison Company. Completion of development is subject to a number of conditions, none of which are assured.
The table below sets forth condensed historical cash flow information for EMG.
Operating cash flow from continuing operations
Operating cash flow from discontinued operations
Net cash provided (used) by financing activities
Net increase in cash and cash equivalents
Cash provided by operating activities from continuing operations decreased $168 million in the first quarter of 2011 compared to the first quarter of 2010 primarily attributable to lower net income and the settlement of derivative contracts in 2010.
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Cash provided by financing activities from continuing operations increased $158 million in the first quarter of 2011 compared to the first quarter of 2010 primarily due to additional borrowing in Viento Funding II refinance and advances under the Laredo and Big Sky financing agreements. The increase also reflects a repayment of debt at Edison Funding Company in 2010.
Cash used by investing activities for the first quarters of 2011 and 2010 primarily consisted of capital expenditures. In addition, cash used by investing activities for the first quarter of 2010 included turbine deposits (investment in other assets) related to wind projects.
Credit ratings for EME, Midwest Generation and EMMT as of March 31, 2011 were as follows:
EME1
Midwest Generation2
EMMT
All the above ratings are on negative outlook. EMG cannot provide assurance that its current credit ratings or the credit ratings of its subsidiaries will remain in effect for any given period of time or that one or more of these ratings will not be lowered. EMG notes that these credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency.
EMG does not have any "rating triggers" contained in subsidiary financings that would result in it being required to make equity contributions or provide additional financial support to its subsidiaries, including EMMT. However, coal contracts at Midwest Generation include provisions that provide the right to request additional collateral to support payment obligations for delivered coal and may vary based on Midwest Generation's credit ratings. Furthermore, EMMT also has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form of adequate assurance of performance in the case of an adverse development affecting the other party.
For a discussion of the effect of EMMT's credit rating on EMG's ability to sell forward the output of the Homer City plant through EMMT, refer to "EMG: Liquidity and Capital Resources—Credit Ratings—Credit Rating of EMMT" in the year-ended 2010 MD&A.
To reduce its exposure to market risk, EMG hedges a portion of its electricity price exposure through EMMT. In connection with entering into contracts, EMMT may be required to support its risk of nonperformance through parent guarantees, margining or other credit support. EMG has entered into guarantees in support of EMMT's hedging and trading activities; however, EMG has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties related to the net of accounts payable, accounts receivable, unrealized losses, and unrealized gains in connection with these hedging and trading activities. For further details, see "Edison International Notes to Consolidated Financial Statements Note 6. Derivative Instruments and Hedging Activities."
Future cash collateral requirements may be higher than the margin and collateral requirements at March 31, 2011, if wholesale energy prices change or if EMMT enters into additional transactions. Certain
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EMMT hedge contracts do not require margin, but contain provisions that require EMG or Midwest Generation to comply with the terms and conditions of their credit facilities. The credit facilities contain financial covenants which are described further in "—Debt Covenants and Dividend Restrictions."
EME's credit facility contains financial covenants which require EME to maintain a minimum interest coverage ratio and a maximum corporate-debt-to-capital ratio as such terms are defined in the credit facility. The following table sets forth the interest coverage ratio:
Ratio
Covenant threshold (not less than)
The following table sets forth the corporate-debt-to-capital ratio:
Corporate-debt-to-capital ratio
Covenant threshold (not more than)
Set forth below are key ratios of EMG's principal subsidiaries required by financing arrangements at March 31, 2011 or for the 12 months ended March 31, 2011:
To pay dividends, Homer City must meet the senior rent service coverage ratio. In addition, Homer City is restricted from paying dividends until the Homer City equity reserve account is replenished. For additional information, see "Edison International Management Overview—Management Overview of EMG—Homer City Outage."
For a more detailed description of the covenants binding EMG's principal subsidiaries that may restrict the ability of those entities to make distributions to EMG directly or indirectly through the other holding companies owned by EMG, refer to "EMG: Liquidity and Capital Resources—Debt Covenants and Dividend Restrictions" in the year ended 2010 MD&A.
EMG is restricted under applicable agreements from selling or disposing of assets, which includes distributions, if the aggregate net book value of all such sales and dispositions during the most recent 12-month period would exceed 10% of consolidated net tangible assets as defined in such agreements computed as of the end of the most recent fiscal quarter preceding the sale or disposition in question. At March 31, 2011, the maximum permissible sale or disposition of EMG assets was $887 million.
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For a discussion of fuel supply contracts , see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments."
For a discussion of the Midwest Generation New Source Review Lawsuit, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies—Midwest Generation New Source Review Lawsuit."
For a discussion of the Homer City New Source Review Lawsuit, see "Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Other Commitments."
For a discussion of EMG's off-balance sheet transactions, refer to "EMG: Liquidity and Capital Resources—Off-Balance Sheet Transactions" in the year ended 2010 MD&A. There have been no significant developments with respect to EMG's off-balance sheet transactions that affect disclosures presented in the 2010 Form 10-K.
For a detailed discussion of EMG's market risk exposures, including commodity price risk, credit risk and interest rate risk, refer to "EMG: Market Risk Exposures" in the year ended 2010 MD&A.
EMG classifies unrealized gains and losses from derivative instruments (other than the effective portion of derivatives that qualify for hedge accounting) as part of operating revenues or fuel costs. The following table summarizes unrealized gains (losses) from non-trading activities:
Non-qualifying hedges
Ineffective portion of cash flow hedges
Homer City plant
Total unrealized gains
At March 31, 2011, cumulative unrealized gains of $5 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($(1) million for the remainder of 2011 and $6 million for 2012).
In determining the fair value of EMG's derivative positions, EMG uses third-party market pricing where available. For further explanation of the fair value hierarchy and a discussion of EMG's derivative instruments, see "Edison International Notes to Consolidated Financial Statements Note 4. Fair Value Measurements" and "Note 6. Derivative Instruments and Hedging Activities," respectively.
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Energy and capacity from the coal plants are sold under terms, including price, duration and quantity, arranged by EMMT with customers through a combination of bilateral agreements (resulting from negotiations or from auctions), forward energy sales and spot market sales. Power is sold into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to generation are generally entered into at the Northern Illinois Hub, and to a lesser extent, the AEP/Dayton Hub, both in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City plant.
The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated for the first quarters of 2011 and 2010:
Northern Illinois Hub
PJM West Hub
Homer City Busbar
The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub and PJM West Hub at March 31, 2011:
2011
April
May
June
July
August
September
October
November
December
2012 calendar "strip"2
Forward market prices at the Northern Illinois Hub and PJM West Hub fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in market rules, electricity demand (which in turn is affected by weather, economic growth, and other factors), plant outages in the region, and the amount of existing and planned power plant capacity. The actual spot prices for electricity delivered by the coal plants into these markets may vary materially from the forward market prices set forth in the preceding table.
EMMT engages in hedging activities for the coal plants to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load requirements services
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contracts and forward contracts accounted for on the accrual basis) at March 31, 2011 for electricity expected to be generated during the remainder of 2011 and in 2012 and 2013:
Northern Illinois and AEP/Dayton Hubs
Homer City plant2,3
The following table summarizes the status of capacity sales for Midwest Generation and Homer City at March 31, 2011:
April 1, 2011 to May 31, 2011
Midwest Generation
June 1, 2011 to May 31, 2012
June 1, 2012 to May 31, 2013
June 1, 2013 to May 31, 2014
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The RPM auction capacity prices for the delivery period of June 1, 2012 to May 31, 2013 and June 1, 2013 to May 31, 2014 varied between different areas of PJM. In the western portion of PJM, affecting Midwest Generation, the prices of $16.46 per MW-day and $27.73 per MW-day were substantially lower than other areas' capacity prices. The impact of lower capacity prices for these periods compared to previous years will have an adverse effect on Midwest Generation's revenues unless such lower capacity prices are offset by an unavailability of competing resources and increased energy prices.
During the three months ended March 31, 2011 and 2010, prices at the Homer City busbar were lower than the PJM West Hub by an average of 9% and 12%, respectively, due to transmission congestion in PJM. During the three months ended March 31, 2011, prices at the individual busbars of the Midwest Generation plants were lower than the AEP/Dayton Hub and Northern Illinois Hub by an average of 10% and 1%, respectively, compared to 11% and 1%, respectively, during the three months ended March 31, 2010, due to transmission congestion in PJM.
The Midwest Generation plants and Homer City plant purchase coal primarily from the Southern PRB of Wyoming and from mines located near the facilities in Pennsylvania, respectively. Coal purchases are made under a variety of supply agreements. The following table summarizes the amount of coal under contract at March 31, 2011 for the remainder of 2011 and the following two years:
EMG is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian (NAPP) coal, which are related to the price of coal purchased for the Homer City plant, increased during 2011 from 2010 year-end prices. The market price of NAPP coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) increased to a price of $76.15 per ton at April 1, 2011, compared to a price of $70 per ton at December 31, 2010, as reported by the Energy Information Administration.
Prices of PRB coal (with 8,800 Btu per pound heat content and 0.8 pounds of SO2 per MMBtu sulfur content) purchased for the Midwest Generation plants fluctuated between $13.25 per ton and $14.75 per ton during the first quarter of 2011. The market price of PRB coal decreased to a price of $13.25 per ton at April 1, 2011, compared to a price of $13.60 per ton at December 31, 2010, as reported by the Energy Information Administration.
EMG has contracts for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various short-haul carriers), which extends through December 31, 2011. EMG is exposed to price risk related to transportation rates after the expiration of its existing transportation contracts. Current market transportation rates for PRB coal are higher than the existing rates under contract. Transportation costs are approximately half of the delivered cost of PRB coal to the Midwest Generation plants.
The federal Acid Rain Program requires electric generating stations to hold SO2 allowances sufficient to cover their annual emissions. Pursuant to Pennsylvania's and Illinois' implementation of the Clean Air Interstate Rule ("CAIR"), coal plants are required to hold seasonal and annual NOx allowances.
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In the event that actual emissions required are greater than allowances held, EMG is subject to price risk for purchases of emission allowances. The market price for emission allowances may vary significantly. The average purchase price of SO2 allowances decreased to $10 per ton during the first quarter of 2011 from $50 per ton in 2010. The average purchase price of annual NOx allowances decreased to $335 per ton during the first quarter of 2011 from $936 per ton in 2010. Based on broker's quotes and information from public sources, the spot price for SO2 allowances and annual NOx allowances was $5 per ton and $227.50 per ton, respectively, at March 31, 2011.
The credit risk exposure from counterparties of merchant energy hedging and trading activities is measured as the sum of net receivables (accounts receivable less accounts payable) and the current fair value of net derivative assets. EMG's subsidiaries enter into master agreements and other arrangements in conducting such activities which typically provide for a right of setoff in the event of bankruptcy or default by the counterparty. At March 31, 2011, the balance sheet exposure as described above, the credit ratings of EMG's counterparties, was as follows:
Credit Rating1
BBB+
BBB
BBB-
Below investment grade
The credit risk exposure set forth in the above table is composed of $80 million of net accounts receivable and payables and $90 million representing the fair value of derivative contracts. The exposure is based on master netting agreements with the related counterparties. Due to developments in the financial markets, credit ratings may not be reflective of the actual related credit risks. In addition to the amounts set forth in the above table, EMG's subsidiaries have posted a $46 million cash margin in the aggregate with PJM, NYISO, Midwest Independent Transmission System Operator ("MISO"), clearing brokers and other counterparties to support hedging and trading activities. The margin posted to support these activities also exposes EMG to credit risk of the related entities.
The coal plants sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transacting in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 68% of EMG's consolidated operating revenues for the three months ended March 31, 2011. At March 31, 2011, EMG's account receivable due from PJM was $55 million.
EMG's wind turbine supply agreements contain significant suppliers' obligations related to the manufacturing and delivery of turbines, and payments, for delays in delivery and for failure to meet performance obligations and warranty agreements. EMG's reliance on these contractual provisions is subject to credit risks. Generally, these are unsecured obligations of the turbine manufacturer. A material adverse development with respect to EMG's turbine suppliers may have a material impact on EMG's wind projects and development efforts.
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Interest rate changes can affect earnings and the cost of capital for capital improvements or new investments in power projects. EMG mitigates the risk of interest rate fluctuations by arranging for fixed rate financing or variable rate financing with interest rate swaps, interest rate options or other hedging mechanisms for a number of its project financings. For details, see "Edison International Notes to Consolidated Financial Statements—Note 5. Debt and Credit Agreements."
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Results of operations for Edison International Parent and Other includes amounts from other Edison International subsidiaries that are not significant as a reportable segment, as well as intercompany eliminations.
Edison International Parent and Other loss from continuing operations was $2 million and $5 million for the three months ended March 31, 2011 and 2010, respectively.
Edison International Parent liquidity and its ability to pay operating expenses and dividends to common shareholders is dependent on dividends from SCE, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to bank and capital markets.
At March 31, 2011, Edison International (parent) had approximately $26 million of cash and equivalents on hand. The following table summarizes the status of the Edison International (parent) credit facility at March 31, 2011:
Edison International has a debt covenant in its credit facility that requires a consolidated debt to total capitalization ratio of less than or equal to 0.65 to 1. At March 31, 2011, Edison International's consolidated debt to total capitalization ratio was 0.53 to 1.
The table below sets forth condensed historical cash flow information for Edison International Parent and Other.
Net cash used by operating activities
Net cash provided by investing activities
Net cash used by operating activities primarily relates to interest, operating costs and income taxes of Edison International (parent). In addition to these factors, Edison International funded a portion of the 2011 tax-allocation payments due by Edison Capital in consideration of an intercompany note receivable.
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Financing activities for the first quarter 2011 were as follows:
Financing activities for the first quarter of 2010 were as follows:
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Significant changes with respect to Edison International (Consolidated) contractual obligations since the filing of the 2010 Form 10-K are discussed in "EMG: Liquidity and Capital Resources—Contractual Obligations and Contingencies" and "SCE: Liquidity and Capital Resources—Contractual Obligations and Contingencies."
For a discussion of Edison International's critical accounting estimates and policies, see "Critical Accounting Estimates and Policies" in the year ended 2010 MD&A.
New accounting guidance is discussed in "Edison International Notes to Consolidated Financial Statements—Note 1. Summary of Significant Accounting Policies—New Accounting Guidance."
Information responding to this item is included in the MD&A under the headings "SCE: Market Risk Exposures" and "EMG: Market Risk Exposures" and is incorporated herein by reference.
Edison International's management, under the supervision and with the participation of the company's Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of Edison International's disclosure controls and procedures (as that term is defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934, as amended (the Exchange Act)) as of the end of the period covered by this report. Based on that evaluation, the Chief Executive Officer and Chief Financial Officer have concluded that, as of the end of the period, Edison International's disclosure controls and procedures are effective.
For a discussion of Edison International's legal proceedings, refer to Edison International Notes to Consolidated Financial Statements—Note 9. Commitments and Contingencies—Contingencies" in the 2010 Form 10-K. There have been no significant developments with respect to legal proceedings specifically affecting Edison International since the filing of the 2010 Form 10-K, except as follows:
In May 2010, the California Coastal Commission issued an NOV to SCE, its contractor, and property owners related to activity on a property that was used for equipment storage related to a nearby SCE electricity line undergrounding construction project. The NOV alleged that SCE, through its contractor, violated the California Coastal Act by removing, without the appropriate permits, approximately one acre of vegetation from the property, which was located in a protected coastal zone within and adjacent to the City of Newport Beach, California. In late 2010, SCE tendered an indemnification claim to its contractor for liability associated with the NOV, which the contractor accepted. In the NOV, the Coastal Commission indicated an interest in negotiating a settlement of the alleged violations. The parties have reached agreement on the penalties portion of the settlement, and SCE has agreed to contribute $50,000. The parties continue to negotiate on the remaining terms of the settlement.
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In March 2011, the U.S. District Court for the Northern District of Illinois dismissed nine of the ten PSD claims asserted against Midwest Generation and EME by the State of Illinois and the Department of Justice, along with claims related to alleged violations of Title V of the CAA to the extent based on the dismissed PSD claims. The Court also dismissed all claims asserted against Commonwealth Edison Company and EME. The Court denied a motion to dismiss a claim by intervenor citizens groups for civil penalties in the remaining PSD claim, but noted that the plaintiffs will be required to convince the Court that the statute of limitations should be equitably tolled. The Court did not address other counts in the complaint that allege violations of opacity and particulate matter limitations under the Illinois State Implementation Plan and Title V of the CAA. Trial of the liability portion of the case is scheduled to commence on June 3, 2013.
January 1, 2011 to January 31, 2011
February 1, 2011 to February 28, 2011
March 1, 2011 to March 31, 2011
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Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
By:
/s/ Mark C. Clarke Mark C. ClarkeVice President and Controller(Duly Authorized Officer andPrincipal Accounting Officer)
Date: May 2, 2011
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