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UNITED STATESSECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
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.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes oNo 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. Derivative Instruments and Hedging Activities
Note 3. Liabilities and Lines of Credit
Note 4. Income Taxes
Note 5. Compensation and Benefit Plans
Note 6. Commitments and Contingencies
Note 7. Consolidated Statements of Changes in Equity
Note 8. Accumulated Other Comprehensive Income
Note 9. Supplemental Cash Flows Information
Note 10. Fair Value Measurements
Note 11. Regulatory Assets and Liabilities
Note 12. Other Income and Expenses
Note 13. Variable Interest Entities
Note 14. Business Segments
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
EDISON INTERNATIONAL OVERVIEW
Introduction
Highlights of Operating Results
SCE Capital Program
SCE 2012 General Rate Case
Environmental Developments
Midwest Generation Environmental Compliance Plans and Costs
Environmental Regulation Developments
EMG Renewables Program
Mitsubishi Lawsuit
Parent Company Liquidity
SOUTHERN CALIFORNIA EDISON COMPANY
RESULTS OF OPERATIONS
Electric Utility Results of Operations
Three Months Ended September 30, 2010 versus September 30, 2009
Utility Earning Activities
Utility Cost-Recovery Activities
Nine Months Ended September 30, 2010 versus September 30, 2009
Supplemental Operating Revenue Information
Income Taxes
LIQUIDITY AND CAPITAL RESOURCES
Available Liquidity
Debt Covenant
Regulatory Proceedings
Energy Efficiency Risk/Reward Incentive Mechanism
2010 FERC Rate Case
Dividend Restrictions
Income Tax Matters
Margin and Collateral Deposits
Historical Consolidated Cash Flows
Condensed Consolidated Statement of Cash Flows
Cash Flows Provided by Operating Activities
Cash Flows Provided (Used) by Financing Activities
Cash Flows Used by Investing Activities
Contractual Obligations and Contingencies
Contractual Obligations
Contingencies
Environmental Remediation
MARKET RISK EXPOSURES
Interest Rate Risk
Commodity Price Risk
Natural Gas and Electricity Price Risk
Credit Risk
EDISON MISSION GROUP
Results of Continuing Operations
Adjusted Operating Income (Loss) ("AOI") – Overview
Adjusted Operating Income from Consolidated Operations
Midwest Generation Plants
Homer City Facilities
Non-GAAP Disclosures—Fossil-Fueled Facilities
Adjusted Operating Income
Seasonal Disclosure—Fossil-Fueled Facilities
Renewable Energy Projects
Energy Trading
Adjusted Operating Income from Leveraged Lease Activities
Adjusted Operating Income from Lease Terminations and Other
Adjusted Operating Income from Unconsolidated Affiliates
Doga
March Point
Seasonal Disclosure
Interest Related Income (Expense)
Results of Discontinued Operations
Derivative Instruments
Unrealized Gains and Losses
Fair Value Disclosures
Small Business Jobs Act of 2010
Capital Investment Plan
Consolidated Cash Flows Provided (Used) by Operating Activities
Consolidated Cash Flows Provided (Used) by Financing Activities
Consolidated Cash Flows Provided (Used) 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 and Financial Ratios
Dividend Restrictions in Major Financings
EME's Senior Notes and Guaranty of Powerton-Joliet Leases
Fuel Supply and Transportation Contracts
Midwest Generation New Source Review Lawsuit
Homer City New Source Review Notice of Violation
Off-Balance Sheet Transactions
Environmental Matters and Regulations
Energy Price Risk Affecting Sales from the Fossil-Fueled Facilities
Capacity Price Risk
Basis Risk
Coal and Transportation Price Risk
Emission Allowances Price Risk
EDISON INTERNATIONAL PARENT AND OTHER
Historical Cash Flow
Condensed Statement of Cash Flows
Cash Flows Used by Operating Activities
EDISON INTERNATIONAL (CONSOLIDATED)
CONTRACTUAL OBLIGATIONS
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
Changes in Internal Control Over Financial Reporting
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Navajo Nation Litigation
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
When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
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ii
iii
Electric utility
Competitive power generation
Total operating revenue
Fuel
Purchased power
Operation and maintenance
Depreciation, decommissioning and amortization
Lease terminations and other
Total operating expenses
Operating income
Interest and dividend income
Equity in income from partnerships and unconsolidated subsidiaries – net
Other income
Interest expense – net of amounts capitalized
Other expenses
Income from continuing operations before income taxes
Income tax expense (benefit)
Income from continuing operations
Income (loss) from discontinued operations – net of tax
Net income
Less: Net income attributable to noncontrolling interests
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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Net Income
Other comprehensive income (loss), net of tax:
Foreign currency translation adjustments – net
Pension and postretirement benefits other than pensions:
Net gain arising during the period
Amortization of net (gain) loss included in net income
Prior service adjustment arising during the period
Amortization of prior service adjustment
Unrealized gain (loss) on derivatives qualified as cash flow hedges:
Unrealized holding gain (loss) arising during the period, net of income tax expense (benefit) of $29 and $(4) for the three months and $41 and $44 for the nine months ended September 30, 2010 and 2009, respectively
Reclassification adjustments included in net income, net of income tax benefit of $5 and $52 for the three months and $54 and $75 for the nine months ended September 30, 2010 and 2009, 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 equivalents
Short-term investments
Receivables, less allowances of $59 and $53 for uncollectible accounts at respective dates
Accrued unbilled revenue
Inventory
Derivative assets
Restricted cash
Margin and collateral deposits
Regulatory assets
Other current assets
Total current assets
Competitive power generation and other property – less accumulated depreciation of $1,794 and $2,231 at respective dates
Nuclear decommissioning trusts
Investments in partnerships and unconsolidated subsidiaries
Other investments
Total investments and other assets
Utility plant, at original cost:
Transmission and distribution
Generation
Accumulated depreciation
Construction work in progress
Nuclear fuel, at amortized cost
Total utility plant
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 6)
Common stock, no par value (800,000,000 shares authorized; 325,811,206 shares issued and outstanding at each date)
Accumulated other comprehensive income
Retained earnings
Total Edison International's common shareholders' equity
Noncontrolling interests
Preferred and preference stock of utility not subject to mandatory redemption
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
Proceeds from U.S. Treasury grants
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
Bonds repurchased
Short-term debt financing – net
Settlements of stock-based compensation – net
Cash contributions from noncontrolling interests
Dividends and distributions to noncontrolling interests
Dividends paid
Net cash provided (used) by financing activities
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Cash flows from investing activities:
Capital expenditures
Purchase of interest in acquired companies
Proceeds from termination of leases
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
Maturities and sale of short-term investments
Purchases of short-term investments
Investments in other assets
Effect of consolidation and deconsolidation of variable interest entities
Net cash used by investing activities
Net increase (decrease) in cash and equivalents
Cash and equivalents, beginning of period
Cash and equivalents, end of period
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Edison International's principal wholly owned subsidiaries are SCE, a rate-regulated electric utility that supplies electric energy to a 50,000 square-mile area of central, coastal and southern California; and EMG, a wholly owned competitive power generation subsidiary. EMG is a holding company whose subsidiaries and affiliates are engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities. EMG's subsidiaries also conduct hedging and energy trading activities in competitive power markets.
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 2009 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, 2010 as discussed below in "—New Accounting Guidance." This quarterly report should be read in conjunction with such financial statements.
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- and nine-month periods ended September 30, 2010 are not necessarily indicative of the operating results for the full year.
The December 31, 2009 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. Except as indicated, amounts presented in the Notes to the Consolidated Financial Statements relate to continuing operations.
Cash and Equivalents
Cash equivalents included money market funds totaling $1.71 billion and $1.46 billion at September 30, 2010 and December 31, 2009, respectively. The carrying value of cash equivalents approximates the fair value, as all investments have maturities of three months or less. For further discussion of money market funds, see Note 10.
Edison International temporarily invests the ending daily cash balance in its primary disbursement accounts until required for check clearing. Edison International reclassified $320 million and $224 million of checks issued against these accounts, but not yet paid by the financial institution, from cash to accounts payable at September 30, 2010 and December 31, 2009, respectively.
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 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. Stock options awarded prior to 2003 and after 2006 were granted without a
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dividend equivalent feature. 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 and assumed conversions available to common shareholders
Incremental shares from assumed conversions
Adjusted weighted average shares – diluted
Diluted earnings per share – continuing operations
Stock-based compensation awards to purchase 9,700,218 and 6,279,410 shares of common stock for the three months ended September 30, 2010 and 2009, respectively, and 6,154,826 and 8,645,549 shares of common stock for the nine months ended September 30, 2010 and 2009, respectively, were outstanding, 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.
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 at September 30, 2010 and December 31, 2009 consisted of the following:
Coal, gas, fuel oil and raw materials
Spare parts, materials and supplies
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 value of the positions. Edison
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International nets margin and cash collateral deposits subject to a master netting arrangement 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
Reflected in other current liabilities
New Accounting Guidance
Accounting Guidance Adopted in 2010
Consolidation – Improvements to Financial Reporting by Enterprises Involved with Variable Interest Entities
The FASB issued an accounting standards update that changes how a company determines when an entity, that is insufficiently capitalized or is not controlled through voting (or similar rights), should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an ability to direct the activities of the entity that most significantly impact the entity's economic performance and whether the entity has an obligation to absorb losses or the right to receive expected returns of the entity. This guidance requires a company to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. Edison International adopted this guidance prospectively effective January 1, 2010. The impact of adopting this guidance resulted in the deconsolidation of assets totaling $683 million and the consolidation of assets totaling $99 million at January 1, 2010, and resulted in a cumulative effect adjustment which increased retained earnings by $15 million. For further discussion, see Note 13.
Fair Value Measurements and Disclosures
The FASB issued an accounting standards update that provides for new disclosure requirements related to fair value measurements. The requirements, which Edison International adopted effective January 1, 2010, include separate disclosure of significant transfers in and out of Levels 1 and 2 and the reasons for the transfers. The update also clarified existing disclosure requirements for the level of disaggregation, inputs and valuation techniques. In addition, effective January 1, 2011, the Level 3 reconciliation of fair value measurements using significant unobservable inputs should include gross rather than net information about purchases, sales, issuances and settlements. The guidance impacts disclosures only. For further discussion, see Note 10.
Accounting Guidance Not Yet Adopted
In October 2009, the FASB issued amended guidance for identifying separate deliverables in a revenue-generating transaction where multiple deliverables exist, and provides guidance for allocating and recognizing revenue based on those separate deliverables. This update also requires additional
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disclosure related to the significant assumptions used to determine the revenue recognition of the separate deliverables. This guidance is effective beginning January 1, 2011 and is required to be applied prospectively to new or significantly modified revenue arrangements. Edison International is currently assessing the effects this guidance may have on its consolidated financial statements.
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 congestion revenue rights ("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 energy produced and sold in the MRTU market as a result of differences between SCE's load requirements versus the amount of energy delivered from its generating facilities, existing bilateral contracts and CDWR contracts allocated to SCE.
A portion of SCE's purchased power supply is subject to natural gas price volatility. SCE's natural gas price exposure arises from purchasing natural gas for generation at the Mountainview power plant and peaker plants, from bilateral contracts where pricing is based on natural gas prices (this includes contract energy prices for some renewable QFs which are based on the monthly index price of natural gas delivered at the southern California border), and power contracts 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 forward arrangements
Natural gas options, swaps and forward arrangements
Congestion revenue rights
Tolling arrangements1
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Fair Value of Derivative Instruments
The following table summarizes the gross and net fair values of commodity derivative instruments at September 30, 2010:
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, 2009:
Income Statement Impact of Derivative Instruments
SCE recognizes realized gains and losses on derivative instruments as purchased-power expense and recovers these costs, subject to reasonableness review, 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 or 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.
The following table summarizes the components of economic hedging activity:
Realized loss
Unrealized gain (loss)
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.
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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 $240 million and $91 million, as of September 30, 2010 and December 31, 2009, respectively, for which SCE has posted no collateral to its counterparties. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2010, SCE would be required to post $16 million of additional collateral based on the contractual terms.
Competitive Power Generation
EMG uses derivative instruments to reduce its exposure to market risks that arise from fluctuations in prices of electricity, capacity, fuel, emission allowances, and transmission rights. Additionally, EMG's financial results can be affected by fluctuations in interest rates. 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 EMG's consolidated balance sheets with offsetting changes recorded in the consolidated statements of income. For transactions that qualify for accounting hedge treatment, the fair value is recognized, to the extent effective, on EMG's consolidated balance sheets with offsetting changes in fair value recognized in accumulated other comprehensive income until the related forecasted transaction occurs.
Derivative instruments that are utilized for trading purposes are measured at fair value and included in the balance sheet as derivative assets or liabilities. Changes in fair value are recognized in the consolidated statements of income.
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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:
Non-trading activities
Cash flow hedges
Trading activities
Netting andcollateral received1
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The following table provides the activity of accumulated other comprehensive income, containing the information about the changes in the fair value of cash flow hedges 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 September 30
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 a net gain of $4 million and $11 million during the third quarters of 2010 and 2009, respectively, and $5 million and $16 million during the nine months ended September 30, 2010 and 2009, respectively, representing the amount of cash flow hedge ineffectiveness and are reflected in "Competitive power generation" revenue on the consolidated statements of income.
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:
Contingent Features/Credit Related Exposure
Certain derivative instruments contain margin and collateral deposit requirements. Since EME's credit ratings are below investment grade, EME has 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 derivative activities. Certain derivative contracts do not require margin, but contain provisions that require EME 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
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by EME 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. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position at September 30, 2010 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME, Midwest Generation or EMMT to termination payments or additional collateral postings under the contingent features described above.
Long-Term Debt
In March 2010, SCE issued $500 million of 5.5% first and refunding mortgage bonds due in 2040. In May 2010, SCE reissued $144 million of 5.0% tax-exempt pollution control bonds due in 2035. In August 2010, SCE issued $500 million of 4.5% first and refunding mortgage bonds due in 2040. These issuances are part of long-term financing plans to fund SCE's capital program.
In July 2010, EMG completed through its subsidiary, Laredo Ridge Wind, LLC, a non-recourse financing of its interests in the Laredo Ridge wind project. The financing included a $53 million bridge loan, secured by the expected U.S. Treasury grant, immediately due to be fully repaid upon receipt of the U.S. Treasury grant and no later than December 31, 2011. As of September 30, 2010, there was $50 million outstanding under the bridge loan at a weighted average interest rate of 2.76% classified as long-term obligations.
EMG consolidated the Ambit project on January 1, 2010. At September 30, 2010, this project had $71 million of bonds payable, which are supported by a letter of credit. Principal payments are due annually through October 1, 2017. Interest rates are reset weekly based on current bond yields for similar securities. The average interest rate for the nine months ended September 30, 2010 was 0.27%. Annual maturities of this debt at September 30, 2010 for the next five years are summarized as follows: $8 million in 2010, $8 million in 2011, $9 million in 2012, $10 million in 2013, and $10 million in 2014. In January 2010, Edison Capital repaid in full its medium-term loans. The balance of these loans was $89 million at December 31, 2009.
In September 2010, Edison International (parent) issued $400 million of 3.75% senior notes due in 2017. The proceeds from these bonds were used to repay short-term borrowings under the revolving credit facility and the remainder for corporate liquidity purposes.
Credit Agreements and Short-Term Debt
In March 2010, SCE replaced its $500 million 364-day revolving credit facility with a new $500 million three-year credit facility that terminates in March 2013.
In March 2010, EMG completed through its subsidiary, Cedro Hill Wind, LLC, a non-recourse financing of its interests in the Cedro Hill wind project. The financing included a $135 million construction loan that is required to be converted to a 15-year amortizing term loan by May 31, 2011, subject to meeting specified conditions. As of September 30, 2010, there was $78 million outstanding under the construction loan at a weighted average interest rate of 3.26%.
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In July 2010, EMG completed through its subsidiary, Laredo Ridge Wind, LLC, a non-recourse financing of its interests in the Laredo Ridge wind project. The financing included a $75 million construction loan required to be converted to a 15-year amortizing term loan by August 31, 2011, subject to meeting specified conditions. As of September 30, 2010, there was $20 million outstanding under the construction loan at a weighted average interest rate of 3.01% classified as a construction loan.
Letters of Credit
Letters of credit issued under SCE's credit facilities aggregated $11 million and are scheduled to expire in twelve months or less. As of September 30, 2010, letters of credit issued under EME and its subsidiaries' credit facilities aggregated $133 million and are scheduled to expire as follows: $8 million in 2010 and $125 million in 2011.
Effective Tax Rate
The table below contains a reconciliation of income tax expense computed at the federal statutory income tax rate to the income tax provision from continuing operations attributable to common shareholders:
Provision for income tax at federal statutory rate of 35%
Increase (decrease) in income tax from:
Items presented with related state income tax, net
Global Settlement related
Change in tax accounting method for asset removal costs
State tax – net of federal benefit
Health care legislation
Production and housing credits
Property-related and other
Total income tax expense from continuing operations
Pre-tax income from continuing operations
Effective tax rate
The CPUC requires flow-through rate-making treatment for the current tax benefit arising from certain property-related and other temporary differences which reverse over time. The accounting treatment for these temporary differences results in recording regulatory assets and liabilities for amounts that would otherwise be recorded to deferred income tax expense.
Global Settlement
During 2010, Edison International recognized a $175 million earnings benefit relating to the Global Settlement, including $138 million in the second quarter resulting from acceptance by the California Franchise Tax Board of the tax positions finalized with the IRS in 2009 and revision to interest recorded on the federal Global Settlement, and $37 million in the third quarter resulting from receipt of the final interest determination from the California Franchise Tax Board.
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During the nine months ended September 30, 2009, Edison International recorded a consolidated after-tax earnings charge of $274 million related to the Global Settlement finalized with the IRS and termination of Edison Capital's cross-border leases ($920 million pre-tax loss). (See discussion of Global Settlement in "Item 8. Edison International Notes to Consolidated Financial Statements—Note 4. Income Taxes" of the 2009 Form 10-K.)
Change in Tax Accounting Method for Asset Removal Costs
During the second quarter of 2010, the IRS approved Edison International's request to change its tax accounting method for asset removal costs primarily related to SCE's infrastructure replacement program. As a result, Edison International recognized a $40 million earnings benefit ($28 million of which relates to asset removal costs incurred prior to 2010) from deducting asset removal costs earlier in the construction cycle. These deductions are recorded on a flow-through basis.
Health Care Legislation
During the first quarter of 2010, Edison International recognized a $39 million non-cash charge to reverse previously recognized federal tax benefits eliminated by the federal health care legislation enacted in March 2010. The Patient Protection and Affordable Care Act, as modified by the Health Care and Education Reconciliation Act, includes a provision that eliminates the federal tax deduction of retiree health care costs to the extent those costs are eligible for federal Medicare Part D subsidies. Although this change does not take effect until January 1, 2013, Edison International is required to recognize the full accounting impact of the legislation in its financial statements in the period of enactment.
Accounting for Uncertainty in Income Taxes
Unrecognized Tax Benefits
The following table provides a reconciliation of unrecognized tax benefits from January 1 to September 30 for 2010 and 2009:
Balance at January 1
Tax positions taken during the current year:
Increases
Tax positions taken during a prior year:
Decreases
Decreases for settlements during the period
Balance at September 30
As of September 30, 2010 and December 31, 2009, respectively, if recognized, $363 million and $374 million of unrecognized tax benefits would impact the effective tax rate.
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Accrued Interest and Penalties
The total amount of accrued interest and penalties related to Edison International's income tax liabilities was $255 million and $380 million as of September 30, 2010 and December 31, 2009, respectively.
The net after-tax interest and penalties recognized in income tax expense was a benefit of $7 million for the three months ended September 30, 2010, compared to an expense of $7 million for the same period in 2009. Net after-tax interest and penalties recognized in income tax expense was a benefit of $95 million and $92 million for the nine months ended September 30, 2010 and 2009, respectively.
The Internal Revenue Service examination phase of Edison International's federal income tax returns for tax years 2003 through 2006 is anticipated to be completed by the end of 2010. During the third quarter, Edison International received a proposed adjustment increasing the taxable gain on the 2004 sale of EME's international assets, which, if sustained, would result in federal and state tax payments of approximately $152 million, including interest. The Internal Revenue Service examination team is considering whether to assess penalties in addition to this proposed tax adjustment. Edison International does not agree with the proposed adjustment and expects to file an appeal with the Internal Revenue Service after the examination phase is completed. Finally, the Internal Revenue Service examination team, during the third quarter, has informed Edison International that it has completed its review of certain other tax positions and will not be proposing adjustments. The IRS examination team may propose additional adjustments prior to completing the 2003 – 2006 examination.
Pension Plans and Postretirement Benefits Other Than Pensions
Pension Plans
During the nine months ended September 30, 2010, Edison International made 2009 plan year contributions of $13 million, 2010 plan year contributions of $82 million and expects to make $30 million of additional 2010 plan year contributions during the remainder of 2010. Annual contributions made to most of SCE's pension plans are recovered through CPUC-approved regulatory mechanisms. Annual contributions to these plans are expected to be, at a minimum, equal to the related annual expense.
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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 nine months ended September 30, 2010, Edison International made 2010 plan year contributions of $22 million and expects to make $33 million of additional 2010 plan year contributions during the remainder of 2010. Annual contributions made to SCE plans are recovered through CPUC-approved regulatory mechanisms and are expected to be, at a minimum, equal to the total annual expense for these plans.
Amortization of prior service cost (credit)
Total expense
Stock-Based Compensation
During the first quarter of 2010, Edison International granted its 2010 stock-based compensation awards, which included stock options, performance shares and restricted stock units. Total stock-based compensation expense (reflected in the caption "Operation and maintenance" on the consolidated statements of income) was $9 million for both the three months ended September 30, 2010 and 2009, and $26 million and $25 million for the nine months ended September 30, 2010 and 2009, respectively. The income tax benefit recognized in the consolidated statements of income was $3 million and $4 million for the three months ended September 30, 2010 and 2009, respectively, and $10 million for both the nine months ended September 30, 2010 and 2009. Excess tax benefits included in "Settlements of stock-based compensation – net" in the financing section of the consolidated statements of cash
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flows were $5 million and $6 million for the nine months ended September 30, 2010 and 2009, respectively.
Stock Options
The following is a summary of the status of Edison International stock options:
Outstanding at December 31, 2009
Granted
Expired
Forfeited
Exercised
Outstanding at September 30, 2010
Vested and expected to vest at September 30, 2010
Exercisable at September 30, 2010
Cash outflows to purchase Edison International shares in the open market to settle stock option exercises were $17 million and $2 million for the three months ended September 30, 2010 and 2009, respectively, and were $30 million and $8 million for the nine months ended September 30, 2010 and 2009, respectively. Cash inflows from participants to exercise stock options were $10 million and $1 million for the three months ended September 30, 2010 and 2009, respectively, and were $19 million and $5 million for the nine months ended September 30, 2010 and 2009, respectively. The tax benefit realized from options exercised was $3 million and less than $1 million for the three months ended September 30, 2010 and 2009, respectively, and $5 million and $1 million for the nine months ended September 30, 2010 and 2009, respectively.
Performance Shares
The following is a summary of the status of Edison International nonvested performance shares:
Nonvested at December 31, 2009
Nonvested at September 30, 2010
There were no performance shares paid in 2009 or 2010.
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Lease Commitments
SCE entered into two 20-year power purchase contracts which are classified as capital leases and are expected to be recorded on the consolidated balance sheets upon commencement of the contracts in 2012 and 2013. SCE's commitments upon commencement are estimated to be: $38 million in 2012, $98 million in 2013, $120 million in 2014, and $2.1 billion for the period remaining thereafter (amounts representing executory costs and interest are $490 million and $911 million, respectively).
Other Commitments
At September 30, 2010, SCE had power purchase contracts with additional commitments estimated to be: $30 million for the remainder of 2010, $94 million in 2011, $77 million in 2012, $53 million in 2013, $49 million in 2014, and $1 billion for the period remaining thereafter.
In October 2010, SCE completed its 2010 annual request for offers and entered into new power purchase contracts with commitments estimated to be: $35 million in 2011, $122 million in 2012, $163 million in 2013, and $69 million in 2014.
At September 30, 2010, EMG's subsidiaries had firm commitments to spend approximately $199 million during the remainder of 2010 and $79 million in 2011 on capital and construction expenditures. These expenditures primarily relate to the construction of wind projects. 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.
EME has entered into various turbine supply agreements with vendors to support its wind development efforts. As of September 30, 2010, EME had commitments, excluding turbines subject to the legal dispute described below, to purchase 46 wind turbines (69 MW) and had 2 wind turbines (6 MW) in storage to be used for future wind projects. EME has payment commitments related to wind turbines of $82 million due in 2011.
Excluded from the turbine commitments referred to above are commitments under a turbine supply agreement between Mitsubishi Power Systems Americas, Inc. and EME, which was subject to a legal dispute as of September 30, 2010. On October 8, 2010, EME and the Mitsubishi entities entered into a settlement agreement with respect to the dispute. As a result of the settlement agreement, EME's $68 million deposit previously paid under the original contract will be applied to the purchase price for 23 wind turbines (55 MW). Within the next three years, EME may elect to deploy 60 additional wind turbines (144 MW). EME 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. EME further agreed to payments of up to $40 million for settlement of remaining disputes on turbines purchased.
At September 30, 2010, Midwest Generation and Homer City had fuel purchase commitments with various third-party suppliers for the purchase of coal. Based on the contract provisions, which consist of fixed prices, subject to adjustment clauses, these minimum commitments are estimated to aggregate $883 million, summarized as follows: $136 million for the remainder of 2010, $461 million in 2011, $253 million in 2012, and $33 million in 2013.
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At September 30, 2010, Midwest Generation and Homer City each had contractual agreements for the transport of coal to their respective facilities. The commitments under these contracts are based on either actual coal purchases or minimum quantities. Accordingly, contractual obligations for transportation based on actual coal purchases are derived from committed coal volumes set forth in fuel supply contracts. The minimum commitments under these contracts are estimated to aggregate $300 million, summarized as follows: $75 million for the remainder of 2010, and $225 million in 2011.
SCE and EME have letters of credit outstanding under their credit facilities. For further discussion, see Note 3.
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 include performance guarantees, guarantees of debt 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 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." The sale-leaseback participants have requested similar indemnification. 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 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 2011. There were approximately 220 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at September 30, 2010. Midwest Generation had recorded a $57 million liability at September 30, 2010 for previous, pending and future claims.
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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 Facilities
In connection with the acquisition of the Homer City facilities, 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 facilities, Homer City agreed to indemnify the lessors for specified environmental liabilities. Due to the nature of the obligation under this indemnity provision, it is not subject to a maximum potential liability and does not have an expiration date. For discussion of the NOV received by Homer City and associated indemnity claims, see "—Contingencies—Homer City New Source Review Notice of Violation." 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 September 30, 2010, EME had recorded a liability of $42 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 asset 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 facilities 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
SCE 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. SCE's obligations under these agreements may be limited in terms of time and/or amount, and in some instances SCE 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. SCE 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 is subject to numerous environmental laws and regulations, which typically require a lengthy and complex process for obtaining licenses, permits and approvals and require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.
Possible developments, such as the enactment of more stringent environmental laws and regulations, proceedings that may be initiated by environmental and other regulatory authorities, cases in which new theories of liability are recognized, and settlements agreed to by other companies that establish precedent or expectations for the power industry, could affect the costs and the manner in which
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business is conducted, and could cause substantial additional capital expenditures or operational expenditures or the ceasing of operations at certain facilities. There is no assurance that any additional costs arising from such developments would be recovered from customers or that Edison International's financial position, results of operations and cash flows would not be materially affected by these developments.
During the third quarter of 2010, Midwest Generation continued its permitting and planning activities for NOx and SO2 controls to meet the requirements of the CPS. Midwest Generation has received all necessary permits from the Illinois EPA allowing the installation of selective non-catalytic reduction (SNCR) technology on multiple units to meet the NOx portion of the CPS, and is engaged with the Illinois EPA with respect to permitting the installation of equipment to meet required reductions for SO2.
Work continued on the possible use of flue gas desulfurization (FGD) technology using dry scrubbing with sodium-based sorbents as a method to comply with the SO2 portion of the CPS. Testing of this technology demonstrated significant reductions in SO2 emissions when using the type of coal used by Midwest Generation. Use of this technology in combination with the type of coal employed by Midwest Generation is expected to require substantially less capital and installation time than the spray dryer absorber technology originally contemplated, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants, depending on competitors' costs. Also, the use of dry scrubbing with sodium-based sorbents to meet environmental regulations will likely require Midwest Generation to incur the costs of upgrading its particulate removal systems.
Based on the work to date, Midwest Generation estimates the cost of retrofitting all units, using dry scrubbing with sodium-based sorbents to comply with CPS requirements for SO2emissions, and associated upgrading of particulate removal systems, would be approximately $1.2 billion in 2010 dollars. If completed, these expenditures would be incurred over multiple years.
Decisions regarding whether or not to proceed with the above projects or other approaches to compliance 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 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 may 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.
Homer City Environmental Issues and Capital Resource Limitations
Homer City operates selective catalytic reduction equipment on all three units to reduce NOx emissions, operates FGD equipment on Unit 3 to reduce SO2 emissions, and uses coal-cleaning equipment on site to reduce the ash and sulfur content of raw coal to meet both combustion and environmental requirements. Homer City may be required to install additional environmental equipment on Unit 1 and Unit 2 to comply with environmental regulations for future operations. For further information, see "—Transport Rule" and "—Homer City New Source Review Notice of
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Violation." Restrictions under the agreements entered into as part of Homer City's 2001 sale-leaseback transaction could affect, and in some cases significantly limit or prohibit, Homer City's ability to incur indebtedness or make capital expenditures. Homer City will have limited ability to obtain additional outside capital for such projects without amending its lease and related agreements. EME is under no contractual obligation to provide funding to Homer City.
Greenhouse Gas Regulation
In June 2010, the US EPA finalized the Prevention of Significant Deterioration ("PSD") and Title V GHG tailoring rule. The effective date of the final rule is August 2, 2010. The emissions thresholds for CO2 equivalents in the final rule are as follows:
Numerous legal challenges to the greenhouse gas tailoring rule have been filed. As written, the rule applies to all sources meeting the thresholds that are built or modified after January 1, 2011. If controls are required to be installed at the facilities of Edison International subsidiaries in the future in order to reduce greenhouse gas emissions pursuant to regulations issued by the US EPA or others, the potential impact will depend on the nature of the controls applied, which remains uncertain.
Transport Rule
In July 2010, the US EPA issued a Notice of Proposed Rulemaking for a proposed rule, known as the Transport Rule, which would require 31 eastern states (including Pennsylvania and Illinois) and the District of Columbia to reduce power plant emissions of NOx and SO2 substantially, starting in 2012, with additional reductions in 2014. The Transport Rule would replace the Clean Air Interstate Rule, which had been remanded to the US EPA in 2008 for revision.
The US EPA has proposed three possible approaches to emissions allowance trading. Under its preferred approach, a pollution limit would be set for each state, intrastate trading would be permitted among power plants, and limited interstate trading would also be permitted consistent with the requirement that each state meet its own pollution control obligations. Under the first alternative, a pollution limit would be set for each state, and only intrastate trading of allowances would be permitted. Under the second alternative, a pollution limit would be set for each state, an emissions limit would be set for each power plant, and limited emissions averaging would be permitted among affected units.
Under the Transport Rule, each covered state would initially be subject to a federal implementation plan designed to reduce pollution that significantly contributed to nonattainment of, or interferes with the maintenance of, NAAQS in other states. States would be able to choose to develop state implementation plans to replace the federal implementation plans.
The Transport Rule is scheduled to be finalized in 2011. The Clean Air Interstate Rule will remain in place until that time. EME believes that the US EPA's preferred approach to emissions allowance trading would provide allowance allocations which are adequate for the Midwest Generation plants based on projected emissions using the Illinois CPS allowable emission rates. If adopted as proposed,
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the Transport Rule may require the installation of additional environmental equipment to reduce SO2 emissions at Units 1 and 2 of the Homer City facilities.
National Ambient Air Quality Standard for Sulfur Dioxide
In June 2010, the US EPA finalized the primary NAAQS for SO2 by establishing a new one-hour standard at a level of 75 parts per billion. The final standard is in line with EME's expectations and is being taken into account in EME's environmental compliance strategy. Revisions to state implementation plans to achieve compliance with the new standard are due to be submitted to the US EPA by February 2014. The US EPA anticipates that the deadline for attainment with the SO2 NAAQS will be August 2017 (five years after the US EPA intends to finalize initial determinations as to the areas of the country that are and are not in attainment with the primary SO2 NAAQS).
Hazardous Substances and Hazardous Waste Laws
In June 2010, the US EPA published proposed regulations relating to coal combustion wastes. Two different proposed approaches are under consideration. The first approach, under which the US EPA would list these wastes as special wastes subject to regulation under Subtitle C of the Resource Conservation and Recovery Act (the section for hazardous wastes), could require EME to incur additional capital and operating costs. The second approach, under which the US EPA would regulate these wastes under Subtitle D of the Resource Conservation and Recovery Act (the section for nonhazardous wastes), is substantially similar to the requirements of existing regulations. Comments on the proposed regulations are due November 19, 2010.
California Renewable Energy Developments
In September 2010, CARB voted to adopt a Renewable Electricity Standard regulation, which would require most retail sellers of electricity in California to procure 33% of their electricity from eligible renewable energy resources by 2020. The potential impact of the Standard will depend on provisions, which have not yet been finalized, and therefore remains uncertain. SCE believes that achieving a 33% renewables portfolio standard in this timeframe will be highly ambitious, given the magnitude of the infrastructure build-out required and the slow pace of transmission permitting and approvals.
Once-Through Cooling
In May 2010, the California State Water Resources Board issued a final policy, which establishes closed-cycle wet cooling as required technology for retrofitting existing once-through cooled plants like San Onofre and many of the existing fossil-fueled power plants along the California coast. The final policy requires an independent engineering study to be completed prior to the fourth quarter of 2013 regarding the feasibility of compliance by California's two coastal nuclear power plants. Depending on the results of the study, the required compliance may result in significant capital expenditures at San Onofre and may affect its operations. The 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 to the extent other coastal power plants in California are forced to shut down or limit operations. The policy has the potential to adversely affect California's nineteen once-through cooled power plants, which provide over 21,000 MW of combined, in-state generation capacity, including over 9,100 MW of capacity interconnected within SCE's service territory.
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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 of September 30, 2010, Edison International's recorded estimated minimum liability to remediate its 29 identified sites at SCE (23 sites) and EME (6 sites primarily related to Midwest Generation) was $42 million, of which $38 million was related to SCE. 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 sites could exceed its recorded liability by up to $228 million, 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. In addition to its identified sites (sites in which the upper end of the range of costs is at least $1 million), SCE also has 34 immaterial sites for which total liability ranges from $5 million (the recorded minimum liability) to $10 million.
The CPUC allows SCE to recover 90% of its environmental remediation costs at certain sites, representing $34 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this mechanism, SCE will recover 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 $39 million 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 $3 million and $2 million for the three months ended September 30, 2010 and 2009, respectively, and were $7 million for both the nine months ended September 30, 2010 and 2009.
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
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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.
Federal and State Income Taxes
Edison International's federal income tax returns are currently under examination by the IRS for tax years 2003 through 2006 and are subject to examination through tax year 2009. Edison International's combined California state franchise tax returns are subject to examination for tax years 1991 through 2009. For further discussion, see Note 4.
In September 2009, the FERC issued an order allowing SCE to implement its proposed 2010 rates effective March 1, 2010, subject to refund. The proposed rates would increase SCE's FERC revenue requirement by $107 million, or 24%, over the 2009 FERC revenue requirement primarily due to an increase in transmission rate base, and would result in an approximate 1% increase to SCE's overall system average rate. SCE has terminated settlement negotiations and begun the litigation process for the proposed 2010 rates. A final decision is expected in the second half of 2011.
FERC Transmission Incentives and CWIP Proceedings
In November 2007, the FERC issued an order granting ROE incentive adders, recovery of the ROE and incentive adders in the CWIP proceedings, and 100% recovery of abandoned plant costs (if any) for three of SCE's transmission projects. The current ROE incentive adders are: 100 basis point adder for DCR, 125 basis point adder for Tehachapi, and 75 basis point adder for Rancho Vista. The CPUC filed an appeal of the November order, which had been stayed pending final resolution by the FERC of the 2008 CWIP proceeding. In April 2010, the FERC issued an order on SCE's 2008 CWIP proceeding. The order sets SCE's 2008 base ROE (before incentives) at 9.54% and establishes a methodology for determining the base ROE for 2009 and 2010 CWIP incentives. In May 2010, SCE filed an application for rehearing with the FERC. The order did not have a material impact on SCE's earnings or cash flows. The collected 2008 through 2010 CWIP revenue requirements are subject to refund, pending a final FERC order on these matters.
Recent Developments
In May 2010, Homer City received an NOV from the US EPA. The new NOV alleges claims similar to those in the 2008 NOV, but it adds nonattainment New Source Review requirements to the alleged PSD violations. It also adds two prior owners of the Homer City facilities as parties.
In July 2010, Homer City received a 60-day Notice of Intent to Sue signed by the State of New York and the Pennsylvania Department of Environmental Protection (PADEP), stating their intent to file a citizen suit based on the same or similar theories advanced by the US EPA in the NOV. The Notice of Intent to Sue also named the sale-leaseback owner participants of the Homer City facilities, Homer City's general partner and limited partner, and two prior owners of the Homer City facilities.
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Background
In June 2008, Homer City received an NOV from the US EPA alleging that, beginning in 1988, Homer City (or former owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the PSD requirements of the CAA. The US EPA also alleges that Homer City has failed to file timely and complete Title V permits. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. On June 30, 2009 and January 2, 2010, the US EPA issued requests for information to Homer City under Section 114 of the CAA. Homer City is working on a response to the requests. Homer City has met with the US EPA and has expressed its intent to explore the possibility of a settlement. If no settlement is reached and the U.S. Department of Justice files suit, litigation could take many years to resolve the issues alleged in the NOV. EME cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations, financial position or cash flows.
Homer City has sought indemnification for liability and defense costs associated with the NOV from the sellers under the asset purchase agreement pursuant to which Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting a portion of defense costs related to the claims.
Homer City notified the sale-leaseback owner participants of the Homer City facilities of the NOV under the operative indemnity provisions of the sale-leaseback documents. The owner participants of the Homer City facilities, in turn, sought indemnification and defense from Homer City for costs and liabilities associated with the Homer City NOV. Homer City responded by recognizing its indemnity obligation and defense of the claims on terms consistent with its contractual obligations.
In March 2010, the Federal District Court for the Northern District of Illinois dismissed nine of the ten counts related to PSD requirements in the complaint filed by the US EPA and the State of Illinois against Midwest Generation, holding that, as a subsequent owner, Midwest Generation could not be held liable under the PSD provisions for modifications allegedly made by Commonwealth Edison, the prior owner of the Midwest Generation plants. The Court also dismissed the tenth count to the extent it sought civil penalties under the CAA, as barred by the applicable statute of limitations. The decision did not address (i) 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, or (ii) the complaint in intervention filed by a group of Chicago-based environmental action groups, which also alleges opacity and particulate matter violations.
In April 2010, the US EPA formally issued to EME the same NOV that was issued to Midwest Generation in 2007. The transmittal letter stated that the action was based on a review of the asset purchase agreement for the Midwest Generation plants and that the NOV was being issued to EME as a successor in interest to Commonwealth Edison.
In June 2010, the US EPA, the State of Illinois, and several environmental groups filed amended complaints in the New Source Review litigation. The amended complaints are similar to the prior complaints, but seek to add Commonwealth Edison and EME as defendants and introduce new legal theories to impose liability on Midwest Generation and EME. Midwest Generation and EME have
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filed a motion to dismiss the amended complaints, and a status hearing has been scheduled for February 2011.
In August 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the PSD requirements and of the New Source Performance Standards of the CAA, including alleged requirements to obtain a construction permit and to install 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. At approximately the same time, Commonwealth Edison received an NOV substantially similar to the Midwest Generation NOV. Midwest Generation, Commonwealth Edison, the US EPA, and the U.S. Department of Justice, along with several Chicago-based environmental action groups, had discussions designed to explore the possibility of a settlement but no settlement resulted.
In August 2009, the US EPA and the State of Illinois filed a complaint in the Northern District of Illinois against Midwest Generation, but not Commonwealth Edison, alleging claims substantially similar to those in the NOV. In addition to seeking penalties ranging from $25,000 to $37,500 per violation, per day, the complaint calls for an injunction ordering Midwest Generation to install 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 those required under the CPS. By order dated January 19, 2010, the Court allowed a group of Chicago-based environmental action groups to intervene in the case.
The owner participants of the Powerton and Joliet Stations have sought indemnification and defense from Midwest Generation and/or EME for costs and liabilities associated with these matters. EME responded by recognizing its indemnity obligation and defense of the claims on terms consistent with its contractual obligations.
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 EME at such time. EME cannot predict the outcome of these matters or estimate the impact on its facilities, its results of operations, financial position or cash flows.
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
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the Navajo Nation did not have a claim for compensation. In September 2010, the Hopi Tribe settled all of its claims and the remaining parties agreed to engage in mediation. SCE cannot predict the outcome of the Navajo Nation's complaint against SCE.
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 $43 million per year. Insurance premiums are charged to operating expense.
Spent Nuclear Fuel
Under federal law, the 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 the ratepayer.
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The following table provides the changes in equity for the nine months ended September 30, 2010:
Balance at December 31, 2009
Other comprehensive loss
Deconsolidation of variable interest entities
Cumulative effect of a change in accounting principle, net of tax
Common stock dividends declared ($0.945 per share)
Dividends, distributions to noncontrolling interests and other
Stock-based compensation – net
Noncash stock-based compensation and other
Balance at September 30, 2010
The following table provides the changes in equity for the nine months ended September 30, 2009:
Balance at December 31, 2008
Common stock dividends declared ($0.93 per share)
Balance at September 30, 2009
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Edison International's accumulated other comprehensive income consists of:
Current period change
Included in accumulated other comprehensive income at September 30, 2010 was $104 million, net of tax, in unrealized gains on EMG's commodity-based cash flow hedges; and an $18 million, net of tax, unrealized loss related to interest rate hedges. The maximum period over which a cash flow hedge is designated is through March 31, 2026.
EMG's 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 $89 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 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. The maximum period over which a commodity cash flow hedge is designated is through May 31, 2014.
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Edison International's supplemental cash flows information is:
Cash payments for interest and taxes
Interest – net of amounts capitalized
Tax payments
Noncash investing and financing activities
Details of debt exchange:
Pollution-control bonds redeemed
Pollution-control bonds issued
Consolidation of variable interest entities:
Assets other than cash
Liabilities and non-controlling interests
Deconsolidation of variable interest entities:
Dividends declared but not paid
Common stock
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 for a liability should reflect the entity's nonperformance risk. Fair value is determined using a hierarchy to prioritize the inputs to valuation models. 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). The three levels of the fair value hierarchy are:
Level 1—Unadjusted quoted prices in active markets that are accessible at the measurement date for identical assets and liabilities;
Level 2—Pricing inputs that 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; and
Level 3—Prices or valuations that require inputs that are both significant to the fair value measurements and unobservable.
Edison International's assets and liabilities carried at fair value primarily consist of derivative contracts, SCE nuclear decommissioning trust investments and money market funds. Derivative contracts are primarily commodity contracts for the purchase and sale of power and gas and include contracts for
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forward physical sales and purchases, options and forward price swaps which settle only on a financial basis (including futures contracts). Derivative contracts can be exchange or over-the-counter traded.
The fair value of derivative contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. Derivatives that are exchange traded in active markets for identical assets or liabilities are classified as Level 1. Investments in money market funds are generally classified as Level 1, as fair value is determined by observable market prices in active markets.
EMG's derivative contracts, valued based on forward market prices in active markets (PJM West Hub, Northern Illinois Hub peak and AEP/Dayton) adjusted for nonperformance risks, are classified as Level 2. EMG obtains forward market prices from traded exchanges (Intercontinental Exchange Futures U.S. or New York Mercantile Exchange) and available broker quotes. Then, EMG selects a primary source that best represents traded activity for each market 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 that EMG believes to provide the most liquid market for the commodity. EMG considers broker quotes to be observable when corroborated with other information which may include a combination of prices from exchanges, other brokers and comparison to executed trades.
SCE's Level 2 derivatives primarily consist of natural gas financial swaps and natural gas physical trades for which SCE obtains the applicable Henry Hub, basis, index, or forward market prices from the New York Mercantile Exchange and Intercontinental Exchange.
Level 3 includes the majority of SCE's derivatives, including over-the-counter options, bilateral contracts, capacity contracts, and QF contracts. The fair value of these derivatives 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.
Level 3 also includes derivatives that trade infrequently (such as firm transmission rights and CRRs in the California market, financial transmission rights traded in markets outside California and over-the-counter derivatives at illiquid locations) and long-term power agreements. For illiquid financial transmission rights and CRRs, objective criteria are reviewed, including system congestion and other underlying drivers, and fair value is adjusted when it is concluded that a change in objective criteria would result in a new valuation that better reflects fair value.
Changes in fair values are based on the hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a 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. 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. Derivative contracts with counterparties that have significant nonperformance risks are classified as Level 3.
The fair value of the derivative assets and liabilities are adjusted for nonperformance risk. To assess nonperformance risk, SCE considers default risk and the loss incurred if a counterparty defaults. EME
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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 fair value of derivative assets and derivative liabilities nonperformance risk was $3 million and $9 million, respectively, at September 30, 2010 and was $4 million and $7 million, respectively, at December 31, 2009.
The SCE 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.
The following tables set 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
Subtotal of commodity contracts
Long-term disability plan
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
Derivative contracts:
Coal
Interest rate contracts
Net assets (liabilities)
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Foreign currency and interest rate contracts
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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 (liability) at beginning of period
Total realized/unrealized gains (losses):
Included in earnings1
Included in regulatory assets andliabilities2
Included in accumulated othercomprehensive income
Purchases and settlements, net
Transfers into or out of Level 3
Fair value, net asset (liability) at endof period
Change during the period in unrealizedgains (losses) related to assets andliabilities 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 2010 and 2009.
Nuclear Decommissioning Trusts
SCE is collecting in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in independent decommissioning trusts. Contributions are approximately $31 million per year. 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.
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The following table sets forth amortized cost and fair value of the trust investments:
Stocks
Corporate bonds
U.S. government andagency securities
Short-term investmentsand 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 $302 million and $503 million for the three months ended September 30, 2010 and 2009, respectively, and $902 million and $1.8 billion for the nine months ended September 30, 2010 and 2009, respectively. Unrealized holding gains, net of losses, were $1.2 billion and $1.1 billion at September 30, 2010 and December 31, 2009, 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:
Balance at beginning of period
Realized gains
Realized losses
Unrealized gains (losses) – net
Other-than-temporary impairment
Interest, dividends, contributions and other
Balance at end of period
Due to regulatory mechanisms, earnings and realized gains and losses (including other-than-temporary impairments) have no impact on operating revenue or earnings.
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Long-term Debt
The carrying amounts and fair values of long-term debt are:
Long-term debt, including current portion
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 approximate fair value and therefore are not included in the table above.
Regulatory assets included on the consolidated balance sheets are:
Current:
Regulatory balancing accounts
Energy derivatives
Other
Long-term:
Deferred income taxes – net
Unamortized nuclear investment – net
Nuclear-related ARO investment – net
Unamortized coal plant investment – net
Unamortized loss on reacquired debt
Pensions and other postretirement benefits
Environmental remediation
Total regulatory assets
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Regulatory liabilities included on the consolidated balance sheets are:
ARO
Costs of removal
Total regulatory liabilities
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 parent
Total other income
Other Expenses:
Civic, political and related activities and donations
Marketing services
Total utility other expenses
Total other expenses
In July 2009, the Mountainview power plant was transferred to utility rate base pursuant to CPUC and FERC approvals which resulted in recognition of $50 million in Equity AFUDC during the three- and nine-month periods ended September 30, 2009.
Effective January 1, 2010, Edison International adopted the FASB's new guidance regarding variable interest entities ("VIEs"). A VIE is defined as a legal entity whose equity owners do not have sufficient
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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 new guidance replaces the predominantly quantitative model for determining which reporting entity, if any, has a controlling financial interest in a VIE with a qualitative approach. Under this new qualitative model, 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 unless specific exceptions or exclusions are met. 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.
Projects or Entities that are Consolidated
At September 30, 2010 and December 31, 2009, EMG had majority interests in 15 wind projects with a total generating capacity of 700 MW that have minority interests held by others. The projects are located in Iowa, Minnesota, New Mexico, Nebraska and Texas. As of December 31, 2009, all of these projects were consolidated by EMG. Upon the application of the new guidance effective January 1, 2010, EMG deconsolidated two of these projects. See further discussion in "—Variable Interests in VIEs that are not Consolidated—Equity Interests." In determining that EMG was the primary beneficiary of the 13 projects consolidated at September 30, 2010, the key factors considered were EMG's ability to direct commercial and operating activities and EMG's obligation to absorb losses and right to receive benefits that could potentially be significant to the variable interest entities.
The following table presents summarized financial information of the wind projects that had minority interests held by others and were consolidated by Edison International:
Current assets
Net property, plant and equipment1
Total assets1
Current liabilities
Long-term obligations net of current maturities
Deferred revenues
Other long-term liabilities
Assets serving as collateral for the debt obligations had a carrying value of $75 million and $81 million at September 30, 2010 and December 31, 2009, respectively, and primarily consist of property, plant and equipment.
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EMG has a 50% partnership interest in the Ambit project. EMG has the power to direct the commercial and operating activities of the project pursuant to the existing contracts and has the obligation to absorb losses and right to receive benefits from the project. Therefore, under the new guidance, EMG is the primary beneficiary which resulted in the consolidation of the Ambit project by Edison International. Total assets consolidated at September 30, 2010 and January 1, 2010 were $99 million at both dates. Substantially all of the assets of the Ambit project are pledged as collateral for the partnership's debt obligations.
Variable Interests in VIEs that are not Consolidated
Power Purchase Contracts
SCE has power purchase agreements ("PPAs") in which it has a variable interest in 17 VIEs, including 6 tolling agreements where SCE provides the natural gas to operate the plants and 11 contracts with QFs (including the Big 4 projects) 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. SCE does not have control over the operation and maintenance of the facilities considered VIEs and it does not bear operational risk of the facilities. See further discussion of the Big 4 projects below.
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, which are accounted for at fair value. See Note 10 for a discussion on nonperformance risk. Further, 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 6. The aggregate capacity dedicated to SCE for these VIE projects was 4,045 MW at September 30, 2010 and the amounts that SCE paid to these projects were $205 million and $184 million for the three months ended September 30, 2010 and 2009, respectively, and $447 million and $414 million for the nine months ended September 30, 2010 and 2009, respectively. These amounts are recoverable in customer rates.
The following table summarizes as of September 30, 2010, SCE's assets and liabilities and exposure to loss associated with SCE's variable interests in the VIEs described above:
Derivatives
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The following table summarizes as of December 31, 2009, SCE's assets and liabilities and exposure to loss associated with SCE's variable interests in the VIEs described above:
Realized and unrealized losses are recovered or expected to be recovered from ratepayers in rates, subject to reasonableness review, and therefore are not reflected in earnings.
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. As of September 30, 2010 and December 31, 2009, EMG had significant variable interests in projects that are not consolidated consisting of the Big 4 projects and the Sunrise project. A subsidiary of EMG operates the 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.
As noted previously in "—Projects or Entities that are Consolidated," EMG deconsolidated two renewable wind energy generating facilities, the Elkhorn Ridge wind project and San Juan Mesa wind project, on January 1, 2010. The commercial and operating activities of these entities are directed by a management committee comprised of representatives of each partner. Thus, EMG is not the primary beneficiary of these projects. Accordingly, effective January 1, 2010, EMG accounts for its interests in these projects under the equity method.
The following table presents the carrying amount of EMG's investments in unconsolidated variable interest entities and the maximum exposure to loss for each investment:
Natural gas-fired projects
Wind projects
EMG's maximum exposure to loss in its variable interest entities 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 on a long-term financing of a project 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 September 30, 2010, entities which EMG has accounted for under the equity method had indebtedness of $141 million, of which $53 million is proportionate to EMG's ownership interest in these projects.
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Big 4 Projects Consolidated Prior to 2010
Edison International has variable interests in the Big 4 Projects through equity interests held by EMG and power contracts between SCE and the Big 4 Projects that contain variable contract pricing provisions based on the price of natural gas. Prior to 2010, Edison International had determined that SCE was the primary beneficiary of these four VIEs and, therefore, consolidated these projects. Edison International deconsolidated the Big 4 Projects at January 1, 2010 since it did not control the commercial and operating activities of these projects through EMG and SCE. Commercial and operating activities are jointly controlled by a management committee of each VIE. Therefore, neither EMG, SCE nor Edison International on a consolidated basis has control of the entities. In addition, EMG's partner provides the executive director and fuel management services and the steam supply is based on the needs of EMG's partner. The deconsolidation did not result in a gain or loss.
The following table presents the carrying amounts of VIEs consolidated by Edison International at December 31, 2009 (these balances were deconsolidated at January 1, 2010):
Cash
Competitive power generation and other property, plant and equipment – net
Noncontrolling interest
Edison International's reportable business segments include its electric utility operation segment (SCE) and a competitive power generation segment (EMG). Prior to January 1, 2010, Edison International reported three business segments: electric utility operations segment, competitive power generation segment and financial services segment. As a result of termination of the cross-border leases during 2009 and the continued decline of the remaining portfolio of the financial services segment, the remaining business activity is no longer significant enough to report separately. Accordingly, the financial services segment has been combined into the competitive power generation segment for all periods presented. The combination of these business activities is consistent with the management structure of EMG and evaluation of performance by Edison International. The significant accounting policies of the segments are the same as those described in Note 1.
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Segment income statement information was:
Operating Revenue (Loss):
Parent and other2
Consolidated Edison International
Net Income (Loss) attributable to Edison International:
Electric utility3
Competitive power generation1,4
Parent and other2,5
Segment balance sheet information was:
Total Assets:
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This MD&A 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, are discussed throughout this MD&A and in the "Risk Factors" section included in Part I, Item 1A of the 2009 Form 10-K. Readers are urged to read this entire report, including the information incorporated by reference, and carefully consider the risks, uncertainties and other factors that affect Edison International's business. Forward-looking statements speak only as of the date they are made and Edison International is not obligated to publicly update or revise forward-looking statements. Readers should review future reports filed by Edison International with the Securities and Exchange Commission.
This MD&A for the three- and nine-month periods ended September 30, 2010 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International since December 31, 2009, and as compared to the three- and nine-month periods ended September 30, 2009. This discussion presumes that the reader has read or has access to Edison International's MD&A for the calendar year 2009 (the "year-ended 2009 MD&A"), which was included in the 2009 Form 10-K.
Except when otherwise stated, references to each of Edison International, SCE and EMG mean each such company with its subsidiaries on a consolidated basis. References to "Edison International (parent)" or "parent company" mean Edison International on a stand-alone basis, not consolidated with its subsidiaries.
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This overview is presented in six sections:
The overview is presented as an update to the overview presented in the 2009 Form 10-K. See pages 62 to 69 of the 2009 Form 10-K for additional information on these topics.
Net Income (Loss) attributable to Edison International
SCE
EMG
Edison International Parent and Other
Edison International Consolidated
Non-Core Earnings (Loss)
Global Settlement1:
EMG2
SCE – tax impact of health care legislation
SCE – regulatory items
EMG discontinued operations
Core Earnings (Loss)
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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 by principal operating subsidiary are also used when communicating with analysts and investors regarding Edison International's earnings results to facilitate comparisons of the 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 excluding income or loss from discontinued operations and income or loss from significant discrete items that management does not consider representative of ongoing earnings, such as: settlement of prior year tax liabilities and changes in tax law; exit activities, including lease terminations, asset impairments, sale of certain assets, early debt extinguishment costs and other activities that are no longer continuing; and non-recurring regulatory or legal proceedings.
SCE's 2010 core earnings increased $52 million and $95 million for the quarter and year-to-date, respectively. The quarter increase was primarily due to higher authorized revenue to support rate base growth and higher capitalized financing costs (AFUDC). The year-to-date increase was due to higher authorized revenue to support rate base growth, lower income tax expense and higher capitalized financing costs (AFUDC). The year-to-date increase was partially offset by higher operating expenses that continue to reflect the impact of curtailed spending last year due to the timing of the 2009 CPUC GRC decision. The year-to-date lower tax expense includes a change in method of tax accounting for asset removal costs primarily related to SCE's infrastructure replacement program.
EMG's 2010 core earnings increased $59 million and decreased $21 million for the quarter and year-to-date, respectively. EMG's third quarter 2010 core earnings were higher than third quarter 2009 core earnings primarily due to higher operating revenues from Midwest Generation and Homer City mostly from higher average realized energy prices, higher capacity revenues, and a gain from the sale of bankruptcy claims. EMG's core earnings for the nine months ended September 30, 2010 were lower than core earnings for the nine months ended September 30, 2009 primarily as a result of higher plant maintenance costs in 2010 due to scheduled plant outages, partially offset by higher energy trading revenues. Energy and fuel related unrealized losses during the nine months ended September 30, 2010 were $30 million compared to unrealized gains of $45 million during the same period last year.
Edison International Parent and Other 2010 core earnings included consolidated state income tax benefits of $14 million during the third quarter. Taxes are provided by SCE and EMG based on tax allocation agreements. Any remaining difference from the consolidated income tax provision and the separate tax provisions of SCE and EMG are reflected in Edison International Parent and Other.
Consolidated non-core items for Edison International included:
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SCE's capital program continues to be focused primarily in five areas:
SCE plans to utilize cash generated from its operations and issuance of additional debt and preferred equity for its capital program. During the nine months ended September 30, 2010, SCE issued long-term debt of $1.1 billion to fund its capital program (see "SCE: Liquidity and Capital Resources—Historical Consolidated Cash Flows—Condensed Consolidated Statement of Cash Flows—Cash Flows Provided (Used) by Financing Activities" for further information).
SCE's capital investments (including accruals) during the nine months ended September 30, 2010 totaled $2.4 billion. SCE projects that capital investments will be in the range of $3.3 billion to $4.0 billion in 2010 and in the range of $18 billion to $21.5 billion for 2010 – 2014. The rate of actual capital spending will be affected by permitting, regulatory, market and other factors as discussed further under "SCE: Liquidity and Capital Resources—Capital Investment Plan" in the 2009 Form 10-K.
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On July 19, 2010, SCE submitted to the CPUC's Division of Ratepayer Advocates its notice of intent ("NOI") to file a 2012 GRC. The NOI indicates that SCE's GRC application, expected to be filed by year-end 2010, will request a 2012 base rate revenue requirement of $6.3 billion. After considering the effects of sales growth, SCE's request would be a $903 million increase over projected 2011 base rate revenue. If the CPUC approves the requested rate increase and allocates the increase to ratepayer groups on a system average percentage change basis, the percentage increases over current base rates and total rates are estimated to be 16.9% and 7.9%, respectively. The requested revenue requirement increase is driven by the need to maintain system reliability, accommodate customer load growth, and increase operation and maintenance expenses primarily for capital-related projects, information technology, insurance and pension contributions. The NOI also indicates that SCE's application will propose a post-test year ratemaking mechanism which would result in 2013 and 2014 incremental base revenue requirement increases, net of sales growth, of $305 million and $542 million, respectively, for the same reasons. The current schedule anticipates a final decision on SCE's 2012 GRC by the end of 2011. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or precisely when a final decision will be adopted.
During the third quarter of 2010, Midwest Generation continued its permitting and planning activities for NOx and SO2controls to meet the requirements of the Combined Pollutant Standard ("CPS"). Midwest Generation has received all necessary permits from the Illinois EPA allowing the installation of selective non-catalytic reduction ("SNCR") technology on multiple units to meet the NOx portion of the CPS, and is engaged with the Illinois EPA with respect to permitting the installation of equipment to meet required reductions for SO2.
Work continued on the possible use of flue gas desulfurization ("FGD") technology using dry scrubbing with sodium-based sorbents as a method to comply with the SO2 portion of the CPS. Testing of this technology demonstrated significant reductions in SO2 emissions when using the type of coal used by Midwest Generation. Use of this technology in combination with the type of coal employed by Midwest Generation is expected to require substantially less capital and installation time than the spray dryer absorber technology originally contemplated, but would likely result in higher ongoing operating costs and may consequently result in lower dispatch rates and competitiveness of Midwest Generation's plants, depending on competitors' costs. Also, the use of dry scrubbing with sodium-based sorbents to meet environmental regulations will likely require Midwest Generation to incur the costs of upgrading its particulate removal systems.
Decisions regarding whether or not to proceed with the above projects or other approaches to compliance 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 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
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applicable at the time decisions are required or made. Due to existing uncertainties about these factors, Midwest Generation may defer final decisions about particular units for the maximum time available. Accordingly, final decisions on whether to install controls, 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.
For a discussion of environmental regulation developments regarding Greenhouse Gas Regulation, the Transport Rule, Coal Combustion Waste Regulation, California Renewable Electricity Standard, and California Once-Through Cooling Policy, see "Edison International Notes to Consolidated Financial Statements—Note 6. Commitments and Contingencies—Contingencies—Environmental Developments."
EMG has five projects totaling 630 MW under construction. In the third quarter, the Community Wind North project, which EME refers to as the CWN project, was moved into construction. The CWN project, a 30 MW wind project in Minnesota, utilizes 28 MW of turbines previously in storage and one turbine on order. In addition to the projects in construction mentioned above, EMG anticipates that construction will begin in 2011 on the Pinnacle project, a 55 MW wind project in West Virginia.
EMG had a development pipeline of potential wind projects with projected installed capacity of approximately 3,700 MW at September 30, 2010. EMG has entered into various turbine supply agreements with vendors to support its wind development efforts. Adjusted for the turbines which EMG may elect to deploy related to the Mitsubishi agreement described below, EMG has commitments to purchase 46 wind turbines (69 MW) to be used for future wind projects. During the second quarter of 2010, EMG deferred the delivery and $82 million in payments for 69 MW of turbines to January 2011. If EMG is unable to develop new projects on acceptable terms and conditions, EMG may terminate the turbine order for these 69 MW, which would result in a material charge related to deposits previously made with the vendor.
The pace of additional growth in EMG's renewables program will be subject to the availability of projects that meet EMG's requirements and the capital needed for development, which will be affected by the extent of internally generated cash flow and future decisions about capital expenditures for environmental compliance by its coal fleet. Consequently, pending substantial progress on or financing of the environmental retrofits, growth of the renewables program may depend upon the availability of third-party capital.
On October 8, 2010, an agreement was reached to settle disputes included in the complaint filed by EME 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, EME committed to purchase on amended terms 23 wind turbines (55 MW), agreed to certain price adjustments on the turbines purchased under the original contract, may elect to deploy 60 additional wind turbines (144 MW) that were part of the original contract, and 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. For additional information regarding the settlement, see "Legal Proceedings" in Part II of this quarterly report.
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The parent company's liquidity and its ability to pay operating expenses and dividends to common shareholders have historically been dependent on dividends from SCE, tax-allocation payments under its tax-allocation agreements with its subsidiaries, and access to bank and capital markets. Given its subsidiaries' plans to use their cash flows for their respective capital needs, Edison International (parent) may incur additional borrowings to fund its dividends to common shareholders and operating expenses. In the third quarter of 2010, Edison International issued $400 million of long-term debt with the proceeds used to repay short-term borrowings under its credit facility, and the remainder for corporate liquidity purposes.
At September 30, 2010, Edison International (parent) had approximately $17 million of cash and equivalents. The following table summarizes the status of the Edison International (parent) credit facility at September 30, 2010:
Commitment
Outstanding borrowings
Outstanding letters of credit
Amount available
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 September 30, 2010, Edison International's consolidated debt to total capitalization ratio was 0.53 to 1.
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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 and taxes on capital projects recovered through balancing account mechanisms. Differences between authorized and actual results impact earnings. Also included in utility earning activities are revenues or penalties related to incentive mechanisms, other operating revenue, and regulatory charges or disallowances, if any.
Utility cost-recovery activities include rates which provide for recovery, subject to reasonableness review, of fuel costs, purchased power costs, certain operation and maintenance expenses (including public purpose related program costs), and depreciation expense related to certain projects. There is no return earned on cost-recovery expenses.
The following table is a summary of SCE's results of operations for the periods indicated. The presentation below separately identifies utility earning activities and utility cost-recovery activities.
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Operating revenue
Fuel and purchased power
Property and other taxes
Net interest expense and other
Income before income taxes
Income tax expense
Net income attributable to noncontrolling interests
Dividends on preferred and preference stock not subject to mandatory redemption
Net income available for common stock
Core Earnings3
Non-Core Earnings:
Regulatory items4
Total SCE GAAP Earnings
Depreciation
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Utility earning activities were primarily affected by the following:
See "—Income Taxes" below for discussion of lower income taxes during the three months ended September 30, 2010 compared to the same period in 2009.
Excluding the impact of deconsolidation of the Big 4 projects (see "Edison International Notes to Consolidated Financial Statements Note 13. Variable Interest Entities"), utility cost-recovery activities were affected by lower purchased power expense of $32 million related to: lower realized losses of $60 million reflecting the impact of higher natural gas prices and changes in SCE's hedge portfolio mix; and lower ISO-related and other energy costs of $45 million. These decreases were partially offset by: higher QF purchased power expense of $35 million primarily due to higher kWh purchases and higher natural gas prices; and higher bilateral energy purchase expense of $25 million, primarily resulting from a new contract.
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Gain on sale of assets
Tax impact of health care legislation
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The first two of the four replacement steam generators were installed in San Onofre Unit 2 in the first quarter of 2010. In October 2010, SCE began the process of installing the final two steam generators at San Onofre Unit 3 which are expected to be placed in service in early 2011. The CPUC has previously adopted a mechanism establishing thresholds for recovery of SCE's incurred costs for the steam generator replacements. Costs above an established threshold will require a reasonableness review. No cost recovery will be allowed for costs incurred that exceed an authorized cap. The determination of whether a reasonableness review of costs is necessary will be made after the steam generator replacement project is completed.
As discussed in the 2009 Form 10-K, the NRC has continued to affirm that San Onofre is being operated safely. However, SCE has had to address a number of regulatory and performance issues for which further corrective action is required to mitigate exposure to events that could have safety significance. In its 2010 mid-cycle performance review letter on September 1st, the NRC noted that although San Onofre had developed corrective actions to resolve previously noted human performance and problem identification and resolution problems, the corrective actions that had been implemented had not been fully effective. The NRC is conducting additional inspections over its baseline program, including inspections to evaluate progress on these matters, and to assess actions taken to improve the working environment for employees to feel free to raise safety concerns. The NRC is also conducting additional public meetings to discuss these issues. SCE continues to implement plans to address the identified issues; however, a number of these issues remain outstanding, and additional issues continue to be identified. To address these regulatory and performance issues, SCE has applied increased management focus and other resources to San Onofre, with an associated
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impact on operations and maintenance costs, as described in the 2009 Form 10-K. On September 2, 2010, SCE appointed a new Chief Nuclear Officer on an interim basis, pending the search for a permanent replacement. SCE anticipates that its corrective actions, and related additional management focus and operations and maintenance costs, will continue beyond 2010. If issues identified by the NRC remain uncorrected, these matters could have a material adverse effect on SCE.
See "—Income Taxes" below for discussion of higher income taxes during the nine-months ended September 30, 2010 compared to the same period in 2009.
Excluding the impact of deconsolidation of the Big 4 projects (see "Edison International Notes to Consolidated Financial Statements Note 13. Variable Interest Entities"), utility cost-recovery activities were primarily affected by:
SCE's retail billed and unbilled revenue (excluding wholesale sales and balancing account (over)/undercollections) was $3.4 billion and $7.8 billion for the three- and nine-month periods ended September 30, 2010, respectively, compared to $3.3 billion and $7.5 billion for the respective periods in 2009. The quarter and year-to-date increases reflect a rate increase of $312 million and $591 million, respectively, and a sales volume decrease of $226 million and $314 million, respectively. The rate increase was due to higher system average rates for 2010 compared to the same periods in 2009 mainly due to the implementation of the CPUC 2009 GRC decision and approved FERC transmission rate changes. The sales volume decrease was due to milder weather experienced during 2010 compared to the same period in 2009 and economic conditions. As a result of the CPUC-authorized decoupling mechanism, SCE does not bear the volumetric risk related to electricity sales (see "Overview of Ratemaking Mechanisms" in the 2009 Form 10-K).
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Due to warmer weather during the summer months and SCE's rate design, operating revenue during the third quarter of each year is generally higher than other quarters.
Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers, CDWR bond-related costs and a portion of direct access exit fees are remitted to the CDWR and are not recognized as revenue by SCE. The amounts collected and remitted to CDWR were $315 million and $896 million for the three- and nine-month periods ended September 30, 2010, respectively, and $493 million and $1.4 billion for the three- and nine-month periods ended September 30, 2009, respectively. Effective January 1, 2010, the CDWR-related rates were decreased to reflect lower power procurement expenses and to refund CDWR overcollections to customers.
SCE's income tax expense from continuing operations decreased $31 million and increased $179 million during the three- and nine-month periods ended September 30, 2010, respectively. The 2010 income tax expense reflects: a $95 million earnings benefit relating to the California impact of the federal Global Settlement, including $53 million in the second quarter resulting from the acceptance by the Franchise Tax Board of the tax positions finalized with the IRS in 2009 and $42 million in the third quarter resulting from receipt of the final interest determination from the Franchise Tax Board; $39 million non-cash charge recorded in the first quarter related to the federal health care legislation enacted in March 2010; and a $40 million earnings benefit due to a change in method of tax accounting for asset removal costs primarily related to SCE's infrastructure replacement program. During the nine months ended September 30, 2009, SCE recognized a $300 million earnings benefit related to the federal Global Settlement finalized with the IRS. See "Edison International Notes to Consolidated Financial Statements Note 4. Income Taxes" for further discussion.
SCE expects to fund its continuing obligations and projected capital investments for 2010 through cash and equivalents on hand, operating cash flows and incremental capital market financings of debt and preferred equity. SCE also has availability under its credit facilities if additional funding and liquidity are necessary to meet operating and capital requirements.
As of September 30, 2010, SCE had approximately $861 million of cash and equivalents and short-term investments. As of September 30, 2010, SCE's long-term debt, including current maturities of long-term debt, was $7.6 billion.
The following table summarizes the status of SCE's credit facilities at September 30, 2010:
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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 September 30, 2010, SCE's debt to total capitalization ratio was 0.46 to 1.
As discussed in the year-ended 2009 MD&A, the CPUC adopted an Energy Efficiency Risk/Reward Incentive Mechanism applicable to the 2006 - 2008 performance period. In September 2010, the CPUC issued a proposed decision and an alternate proposed decision for the final payment. The proposed decision, if adopted, would result in no final payment, whereas, the alternate proposed decision, if adopted, would result in SCE receiving the previously projected $27 million final payment. SCE expects a CPUC decision on the final payment, if any, in late 2010. There is no assurance that SCE will receive a final payment.
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 September 30, 2010, SCE's 13-month weighted-average common equity component of total capitalization was 51.1% resulting in the capacity to pay $502 million in additional dividends.
SCE paid dividends to its parent, Edison International, of $100 million in both January 2010 and in September 2010. Future dividend amounts and timing of distributions are dependent upon several factors, including the actual level of capital investments, operating cash flows and earnings.
In September 2010, President Obama signed the Small Business Jobs Act of 2010, which extended the 50% bonus depreciation provision for an additional year to include property purchased and placed into service by December 31, 2010. SCE expects that certain capital expenditures incurred during 2010 will qualify for the accelerated bonus depreciation, which would provide additional cash flow benefits in 2010, estimated to be in the range of approximately $250 million to $300 million.
Certain derivative instruments and power procurement contracts under SCE's power and natural gas hedging activities contain collateral requirements. The table below illustrates the amount of collateral
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posted by SCE to its counterparties, as well as the potential collateral that would be required if SCE's credit rating fell below investment grade.
Collateral posted as of September 30, 20101
Incremental collateral requirements if SCE's credit rating was downgraded below investment grade
Total posted and potential collateral requirements2
This section discusses consolidated cash flows from operating, financing and investing activities.
Cash flows provided by operating activities
Cash flows provided (used) by financing activities
Cash flows used by investing activities
Cash provided by operating activities decreased $625 million for the nine months ended 2010, compared to the same period in 2009 reflects lower net tax receipts in 2010 primarily resulting from the impacts of the Global Settlement. As a result of the Global Settlement, SCE received net tax allocation payments from Edison International of approximately $295 million and $875 million in 2010 and 2009, respectively. The 2010 change was also due to the timing of cash receipts and disbursements related to working capital items.
Financing activities for the first nine months of 2010 were as follows:
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Financing activities for the first nine months of 2009 were as follows:
Cash flows from investing activities are driven primarily by capital expenditures and funding of nuclear decommissioning trusts. Cash paid for capital expenditures was $2.7 billion and $2.1 billion for the nine months ended September 30, 2010 and 2009, respectively, primarily related to transmission and distribution investments. Net purchases of nuclear decommissioning trust investments and other were $133 million and $163 million for the nine months ended September 30, 2010 and 2009, respectively.
SCE's long-term principal debt maturities plus interest payments as of September 30, 2010 are estimated to be: $102 million for the remainder of 2010, $408 million in 2011, $408 million in 2012, $408 million in 2013, $1.4 billion in 2014, and $13 billion for the period remaining thereafter. These amounts have been updated to reflect SCE's financing activities completed during 2010. For a discussion of issuances of long-term debt, see "Edison International Notes to Consolidated Financial Statements Note 3. Liabilities and Lines of Credit—Long-Term Debt."
For a discussion of purchase obligations and capital lease obligations, see "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Lease Commitments and—Other Commitments."
Developments related to SCE's 2010 FERC Rate Case, FERC Transmission Incentives and CWIP Proceedings, Navajo Nation Litigation and Spent Nuclear Fuel are discussed in "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies."
As of September 30, 2010, SCE identified 23 sites for remediation and recorded an estimated minimum liability of $38 million. SCE expects to recover 90% of its remediation costs at certain sites. SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the
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next several years are expected to range from $3 million to $18 million. See "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies" for further discussion.
For a detailed discussion of SCE's market risk exposures, including commodity price risk, credit risk and interest rate risk, see "SCE: Market Risk Exposures—Commodity Price Risk" in the year-ended 2009 MD&A.
At September 30, 2010, the fair market value of SCE's long-term debt (including current portion of long-term debt) was $8.7 billion, compared to a carrying value of $7.6 billion. At September 30, 2010, SCE did not believe that its short-term debt was subject to interest rate risk due to the fair value being approximately equal to the carrying value.
The following table summarizes the fair values of outstanding derivative instruments used at SCE to mitigate its exposure to spot market prices. For further discussion on fair value measurements, see "Edison International Notes to Consolidated Financial Statements Note 10. Fair Value Measurements."
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The change in the fair value of derivative contracts for the nine months ended September 30, 2010 was as follows:
Fair value of derivative contracts, net liability at January 1, 2010
Total realized/unrealized net losses:
Included in regulatory assets and liabilities1
Fair value of derivative contracts, net liability at September 30, 2010
SCE recognizes realized gains and losses on derivative instruments as purchased power expense and recovers these costs, subject to reasonableness review, 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 or liabilities and therefore are not reflected in earnings. Realized losses on economic hedging activities were primarily due to settled natural gas prices being lower than contract prices. Unrealized losses on economic hedging activities were primarily due to the declining gas and power prices related to SCE's new generation contracts and the decreasing forward natural gas prices related to financial natural gas contracts.
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 arrangements. As of September 30, 2010, the amount of balance sheet exposure as described above broken down by the credit ratings of SCE's counterparties, was as follows:
S&P Credit Rating1
A or higher
A-
BBB+
BBB
BBB-
Below investment grade and not rated
The credit risk exposure set forth in the above table is composed of less than $1 million of net account receivables and $187 million representing the fair value, adjusted for counterparty credit reserves, of derivative contracts.
The CAISO comprises 94% of the total net exposure above and is mainly related to the CRRs' fair value (see "—Commodity Price Risk" for further information).
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The following table is a summary of EMG's results of operations. Effective January 1, 2010, Edison International combined the competitive power generation and financial services segments into one business segment. The change resulted from termination of cross-border leases during 2009 and the continued decline of the remaining portfolio of the financial services segment. Accordingly, the financial services segment has been combined retroactively for all periods presented into one business segment. The combination of these business activities is consistent with the management structure of EMG and evaluation of performance by Edison International.
This section discusses operating results for the three- and nine-month periods ended September 30, 2010 and 2009. EMG's continuing operations include the fossil-fueled facilities, 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
Operating income (loss)
Income (loss) from continuing operations before income taxes
Income (loss) from continuing operations
Net income (loss)
Less: Net loss attributable to noncontrolling interests
Net income (loss) available for common stock
Core Earnings1
Non-Core Earnings (Loss):
Global Settlement2
Discontinued Operations
Total EMG GAAP Earnings (Loss)
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EMG's third quarter 2010 core earnings were higher than third quarter 2009 core earnings primarily due to the following:
EMG's core earnings for the nine months ended September 30, 2010 were lower than core earnings for the nine months ended September 30, 2009 primarily due to the following pre-tax items:
The decreases were partially offset by the following pre-tax items:
Consolidated non-core items for EMG included:.
The following section and table provide a summary of results of EMG's operating projects and corporate expenses for the third quarters of 2010 and 2009 and nine months ended September 30, 2010
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and 2009, 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 facilities
Renewable energy projects
Energy trading
Big 4 projects
Sunrise
Westside projects
Leveraged lease income
Other projects
Other operating income (expense)
Corporate administrative and general
Corporate depreciation and amortization
AOI1
The following table reconciles AOI to operating income as reflected on EMG's consolidated statements of income:
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The following table presents additional data for the Midwest Generation plants:
Operating Revenues
Operating Expenses
Fuel1
Plant operations
Plant operating leases
Depreciation and amortization
Administrative and general
Operating Income
Other Income
AOI
Statistics
Generation (in GWh)
Energy contracts
Load requirements services contract
AOI from the Midwest Generation plants increased $81 million for the third quarter ended September 30, 2010, compared to the corresponding period of 2009. The third quarter increase in AOI was primarily attributable to an increase in realized energy prices, a gain from the sale of the bankruptcy claims against Lehman, and higher capacity revenues, partially offset by unrealized losses in 2010 compared to unrealized gains in 2009. Average realized fuel costs were lower due to lower emission allowance costs.
During the third quarter of 2010, EMG sold its claims against Lehman and recorded a gain of $24 million. The claims originated from power contracts that were terminated in 2008 due to the bankruptcy of Lehman. During 2008, EMG dedesignated the contracts as cash flow hedges due to nonperformance risks and recorded unrealized losses of $24 million.
AOI from the Midwest Generation plants decreased $59 million for the nine months ended September 30, 2010, compared to the corresponding period of 2009. The 2010 decrease in AOI was primarily attributable to an increase in plant maintenance costs during the first half of 2010, lower
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realized energy prices and unrealized losses in 2010 compared to unrealized gains in 2009, partially offset by higher capacity revenues, a gain from the sale of the bankruptcy claims discussed above, and lower emission allowance costs. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Average realized fuel costs were lower in the nine months ended September 30, 2010 as compared to the same period in 2009 due to lower emission allowance costs partially offset by higher costs related to activated carbon, which is used to reduce mercury emissions.
Included in operating revenues were unrealized gains (losses) of $(16) million and $2 million for the third quarters of 2010 and 2009, respectively, and $(12) million and $22 million for the nine months ended September 30, 2010 and 2009, respectively. Unrealized gains (losses) in 2010 and 2009 were primarily due to economic hedge contracts that are accounted for on a mark-to-market basis.
Included in fuel costs were unrealized gains (losses) of $2 million and $(2) million for the third quarters of 2010 and 2009, respectively, and $(5) million and $12 million for the nine months ended September 30, 2010 and 2009, respectively. Unrealized gains (losses) were due to oil futures contracts which were accounted for as economic hedges related to a fuel adjustment mechanism of a rail transportation contract.
For more information regarding forward market prices and unrealized gains (losses), see "EMG: Market Risk Exposures—Commodity Price Risk" and "—Derivative Instruments," respectively.
The following table presents additional data for the Homer City facilities:
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AOI from the Homer City facilities decreased $4 million for the third quarter ended September 30, 2010, compared to the corresponding period of 2009. The third quarter decrease in AOI was primarily attributable to lower unrealized gains and higher coal costs, partially offset by higher average realized energy prices. Forced outages were higher in the third quarter of 2010 due to opacity-related deratings and unscheduled outages. Higher average fuel costs compared to 2009 were attributable to higher coal costs, partially offset by lower emission allowance costs.
AOI from the Homer City facilities decreased $50 million for the nine months ended September 30, 2010, compared to the corresponding period of 2009. The 2010 decrease in AOI was primarily attributable to unrealized losses in 2010 compared to unrealized gains in 2009, an increase in plant operations costs related to scheduled plant outages, and lower realized energy revenues, partially offset by higher capacity revenues. The Homer City facilities experienced increased forced outages in 2010 compared to 2009 due to opacity-related deratings and unscheduled outages. Plant maintenance and overhaul related expenses were higher in 2010 due to the deferral of plant outages in 2009. Higher average fuel costs compared to 2009 were attributable to higher coal costs.
Included in operating revenues were unrealized gains (losses) from hedge activities of $1 million and $6 million for the third quarters of 2010 and 2009, respectively, and $(13) million and $11 million for the nine months ended September 30, 2010 and 2009, respectively. Unrealized gains (losses) in 2010 and 2009 were primarily attributable to 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 the 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 facilities is delivered into the transmission system). For more information regarding forward market prices and unrealized gains (losses), see "EMG: Market Risk Exposures—Commodity Price Risk" and "—Derivative Instruments."
AOI is equal to operating income (loss) plus other income (expense) for the fossil-fueled facilities. AOI is a non-GAAP performance measure and may not be comparable to those of other companies. Management believes that inclusion of other income (expense) is meaningful for investors as the components of other income (expense) are integral to the operating results of the fossil-fueled facilities.
Due to fluctuations in electric demand resulting from warmer weather during the summer months and cold weather during the winter months, electric revenues from the fossil-fueled facilities normally vary substantially on a seasonal basis. In addition, maintenance outages generally are scheduled during periods of lower projected electric demand (spring and fall), further reducing generation and increasing major maintenance costs which are recorded as an expense when incurred. Accordingly, AOI from the fossil-fueled facilities 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 Fossil-Fueled Facilities."
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The following table presents additional data for EMG's renewable energy projects:
Production Tax Credits
Net Loss Attributable to Noncontrolling Interest
Generation (in GWh)2
Less:
Production tax credits
Net loss attributable to noncontrolling interest
Operating Loss
AOI from renewable energy projects increased $8 million for the third quarter ended September 30, 2010, compared to the corresponding periods of 2009. The third quarter increase in AOI was primarily attributable to higher generation resulting from an increase in projects in operation. AOI in the third quarter and nine months ended September 30, 2009 included $1 million and $17 million, respectively, of liquidated damages from availability guarantees provided by a wind turbine supplier, which compensated EMG for lower generation (none recorded in 2010). During the nine months ended September 30, 2010, EMG received $92 million in U.S. Treasury grants, which was recorded as deferred revenue and is recognized as revenue over the life of the project.
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EMG seeks to generate profit by utilizing its subsidiary, EMMT, to engage in trading activities 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 increased $14 million and $65 million for the third quarter and nine months ended September 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 increases in AOI from energy trading activities were attributable to increased revenues in congestion and basis trading.
AOI from leveraged lease income increased $1 million and decreased $9 million for the third quarter and nine months ended September 30, 2010, respectively, compared to the corresponding periods of 2009 due to the termination of the cross-border leases and the sale of a lease investment during the first half of 2009.
AOI from lease terminations and other included gains of $1 million and losses of $888 million for the third quarter and nine months ended September 30, 2009, respectively, due to the termination of the cross-border leases (see "Edison International Notes to Consolidated Financial Statements Note 4. Income Taxes" of the 2009 Form 10-K for further information).
AOI from the Doga project increased $7 million for the nine months ended September 30, 2010, compared to the corresponding period of 2009 due to the timing of distributions. AOI is recognized when cash is distributed from the project since the Doga project is accounted for on the cost method.
AOI from the March Point project decreased $4 million and increased $10 million for the third quarter and nine months ended September 30, 2010, respectively, compared to the corresponding periods of 2009. The 2010 year-to-date increase was primarily 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.
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.
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Interest income
Interest expense
EME debt
Non-recourse debt
The 2010 decrease in interest expense was primarily due to higher capitalized interest and lower debt balances under EME's and Midwest Generation's credit facilities, partially offset by higher wind project financing. Capitalized interest for projects under construction increased $14 million and $27 million for the third quarter and nine months ended September 30, 2010, respectively, compared to the corresponding periods of 2009.
EMG's income taxes from continuing operations for the nine months ended September 30, 2010 included a $52 million income tax benefit resulting from acceptance by the California Franchise Tax Board's of the tax positions finalized with the IRS as part of the Global Settlement for tax years 1986 through 2002. In addition, income taxes for the nine months ended September 30, 2010 and 2009, included tax benefits of production and housing tax credits of $50 million during each period.
For further discussion, see "Edison International Notes to Consolidated Financial Statements Note 4. Income Taxes."
Income from discontinued operations, net of tax, decreased $3 million and increased $9 million for the third quarter and nine months ended September 30, 2010, respectively, compared to the corresponding periods of 2009. The third quarter decrease was due to higher foreign exchange rates. The year-to-date increase was due to lower foreign exchange rates, adjustments to unrecognized tax benefits, and a reduction in EMG's estimated liability due primarily to expiration of a contract indemnity during the first quarter of 2010. EMG increased its estimated liability for a tax indemnity by $6 million in the nine months ended September 30, 2009.
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 results of derivative activities are recorded as part of cash flows from operating activities on the consolidated
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statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities:
Non-qualifying hedges
Ineffective portion of cash flow hedges
Total unrealized gains (losses)
At September 30, 2010, cumulative unrealized gains of $12 million were recognized from non-qualifying hedge contracts or the ineffective portion of cash flow hedges related to subsequent periods ($4 million for the remainder of 2010, $7 million for 2011, and $1 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 10. Fair Value Measurements" and "Note 2. Derivative Instruments and Hedging Activities," respectively, and refer to "EMG: Results of Operations—Fair Value of Derivative Instruments" in the year-ended 2009 MD&A.
At September 30, 2010, EMG and its subsidiaries had consolidated cash and equivalents of $1.1 billion and a total of $960 million of capacity under its credit facilities. EMG's consolidated debt (including short-term debt) at September 30, 2010 was $4.2 billion, of which $141 million was current. In addition, EMG's subsidiaries had $3.0 billion of long-term lease obligations related to their sale-leaseback transactions that are due over periods ranging up to 24 years.
The following table summarizes the status of the EME and Midwest Generation credit facilities at September 30, 2010:
Less: Commitment from Lehman Commercial Paper Inc.
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As a result of credit ratings actions in 2010, the margins applicable to Midwest Generation's $500 million working capital facility increased 27.5 basis points. Borrowings made under this credit facility currently bear interest at LIBOR plus 1.15%, unless average utilized commitments during a period exceed $250 million, in which case the margin increases to 1.275%.
Expenditures for NOx and SO2 controls through 2012 (estimated at $315 million), are anticipated to be funded through operating cash flow and available credit facilities. EMG has not yet committed to the completion of environmental compliance activities for all the Midwest Generation plants. Depending upon the facilities selected to be retrofit and the timing of funding requirements beyond the near term, EMG may utilize operating cash flow or seek debt financing to fund capital expenditures.
Capital expenditures to complete renewable-related projects through 2011 are projected to be $511 million at September 30, 2010. EMG anticipates that renewable project capital investment will be funded using construction financing, U.S. Treasury grants and existing EMG liquidity. The following table summarizes the projected funding sources:
Secured project financings
Big Sky1
Cedro Hill1
Laredo Ridge1
Anticipated U.S. Treasury grants2
EMG may from time to time seek to retire or purchase its outstanding debt through cash purchases and/or exchange offers, in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, EMG's liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.
In September 2010, the Small Business Jobs Act of 2010 extended the 50% bonus depreciation provision for an additional year to include property purchased and placed into service by December 31, 2010. EMG expects that certain capital expenditures incurred during 2010 will qualify for the accelerated bonus depreciation, which would provide additional cash flow benefits, primarily in 2011, estimated to be in the range of approximately $70 million to $100 million.
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At September 30, 2010, forecasted capital expenditures through 2012 by EMG's subsidiaries for existing projects, corporate activities and turbine commitments were as follows:
Plant capital expenditures
Environmental expenditures1
Environmental expenditures2
Renewable Projects
Capital and construction expenditures3
Turbine commitments4
Other capital expenditures
Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls, replacement of major boiler components, generator stator rewinds, 4Kv switchgear and main power transformer replacement.
Midwest Generation is subject to various commitments with respect to environmental compliance. Expenditures, in addition to those included on the preceding table, are anticipated and could be material; however, the amounts and timing have not been determined. For more information on the current status of environmental improvements in Illinois, see "Edison International
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Overview—Environmental Developments." For further discussion of environmental regulations, refer to "Environmental Regulation of Edison International and Subsidiaries" in the Form 2009 10-K.
This section discusses EMG's consolidated cash flows from operating, financing and investing activities.
Operating cash flow provided (used) by continuing operations
Operating cash flow provided (used) by discontinued operations
Net cash provided (used) by operating activities
Net cash provided (used) by investing activities
Net decrease in cash and cash equivalents
Cash provided by operating activities from continuing operations increased $1.4 billion in the first nine months of 2010, compared to the first nine months of 2009. The 2010 increase was primarily due to the impacts of the Global Settlement and derivative-related activities. In April 2010, Edison Capital funded a $253 million deposit to the IRS related to the Global Settlement. In 2009, Edison Capital made a net tax allocation payment to Edison International of $1.1 billion related to the termination of Edison Capital's interest in cross-border leases (see "Item 8. Edison International Notes to Consolidated Financial Statements Note 4. Income Taxes" of the 2009 Form 10-K for further discussion).
Cash provided by financing activities from continuing operations increased $276 million in the first nine months of 2010, compared to the first nine months of 2009. In 2010, financing activities included project-level wind financing. Financing activities in 2009 included wind project financings and the repayment of $188 million and $200 million under EME's corporate credit facility and Midwest Generation's working capital facility, respectively. For further project financing details, see "Edison International Notes to Consolidated Financial Statements Note 3. Liabilities and Lines of Credit." In addition, in January 2010, Edison Capital redeemed in full its $89 million medium-term loans.
Cash used in investing activities from continuing operations decreased $1.4 billion in the first nine months of 2010, compared to the first nine months of 2009. The 2010 decrease was primarily due to $1.385 billion of net proceeds from termination of the cross-border leases at Edison Capital in 2009. The change was also due to capital expenditures for the construction of wind projects. In 2009, investments in other assets include wind turbine deposits.
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Credit ratings for EME, Midwest Generation and EMMT as of September 30, 2010 are as follows:
EME1
Midwest Generation2
EMMT
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 discussions of contingent features related to energy contracts, see "—Margin, Collateral Deposits and Other Credit Support for Energy Contracts."
For a discussion of the effect of EMMT's credit rating on EMG's ability to sell forward the output of the Homer City facilities through EMMT, refer to "EMG: Liquidity and Capital Resources—Credit Ratings—Credit Rating of EMMT" in the year-ended 2009 MD&A.
Future cash collateral requirements may be higher than the margin and collateral requirements were at September 30, 2010, if wholesale energy prices change or if EMMT enters into additional transactions. EMG estimates that margin and collateral requirements for energy and congestion contracts outstanding as of September 30, 2010 could increase by approximately $129 million over the remaining life of the contracts using a 95% confidence level. This increase may not be offset by similar changes in the cash flows of the underlying hedged items in the same periods. Certain EMMT hedge contracts do not require margin, but contain provisions that require EME 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."
Hedge contracts include provisions relating to a change in control or material adverse effect resulting from amendments or modifications to the related credit facility. EMMT has hedge contracts that do not require margin, but contain the right of each party to request additional credit support in the form
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of adequate assurance of performance in the case of an adverse development affecting the other party. The aggregate fair value of all derivative instruments with credit-risk-related contingent features is in an asset position at September 30, 2010 and, accordingly, the contingent features described above do not currently have a liquidity exposure. Future increases in power prices could expose EME or Midwest Generation to termination payments or additional collateral postings under the contingent features described above.
Midwest Generation has cash on hand and a credit facility to support margin requirements specifically related to contracts entered into by EMMT related to the Midwest Generation plants. In addition, EME has cash on hand and a credit facility to provide credit support to subsidiaries. For a discussion on available borrowing capacity under Midwest Generation and EME credit facilities, see "—Available Liquidity."
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 EME's principal subsidiaries required by financing arrangements at September 30, 2010 or for the 12 months ended September 30, 2010:
Midwest Generation (Midwest Generation plants)
Debt to Capitalization Ratio
Less than or equal to0.60 to 1
Homer City (Homer City facilities)
Senior Rent Service Coverage Ratio
Greater than 1.7 to 1
For a more detailed description of the covenants binding EME's principal subsidiaries that may restrict the ability of those entities to make distributions to EME directly or indirectly through the other holding companies owned by EME, refer to "EMG: Liquidity and Capital Resources—Debt Covenants and Dividend Restrictions in Major Financings" in the year-ended 2009 MD&A.
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EME is restricted under applicable agreements from the sale or disposition 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 September 30, 2010, the maximum permissible sale or disposition of EME assets was $834 million.
For a discussion of fuel supply contracts and coal transportation agreements, see "Edison International Notes to Consolidated Financial Statements Note 6. 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 6. Commitments and Contingencies—Contingencies—Midwest Generation New Source Review Lawsuit."
For a discussion of the Homer City New Source Review Notice of Violation, see "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies—Homer City New Source Review Notice of Violation."
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 2009 MD&A. There have been no significant developments with respect to EMG's off-balance sheet transactions that affect disclosures presented in Edison International's 2009 Form 10-K.
For a discussion of EMG's environmental matters, refer to "Environmental Matters and Regulations" in Item 1 in the year-ended 2009 Form 10-K. There have been no significant developments with respect to environmental matters specifically affecting EMG since the filing of the 2009 Form 10-K, except as set forth in "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies—Environmental Developments."
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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 2009 MD&A.
Energy and capacity from the fossil-fueled facilities 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 or the AEP/Dayton Hub, both in PJM, for the Midwest Generation plants and generally at the PJM West Hub for the Homer City facilities. These trading hubs have been the most liquid locations for hedging purposes.
The following table depicts the average historical market prices for energy per megawatt-hour at the locations indicated for the first nine months of 2010 and 2009:
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 September 30, 2010:
2010
October
November
December
2011 calendar "strip"2
2012 calendar "strip"2
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Forward prices for the 2011 calendar strip indicated on the preceding table have decreased from December 31, 2009 prices of $34.73 and $49.43 for the Northern Illinois Hub and the PJM West Hub, respectively.
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 fossil-fueled facilities into these markets may vary materially from the forward market prices set forth in the preceding table.
EMMT engages in hedging activities for the fossil-fueled facilities to hedge the risk of future change in the price of electricity. The following table summarizes the hedge positions (including load requirements services contracts and forward contracts accounted for on the accrual basis) as of September 30, 2010 for electricity expected to be generated during the remainder of 2010 and in 2011 and 2012:
Northern Illinois and AEP/Dayton Hubs
Homer City facilities2,3
In addition, as of September 30, 2010, EMMT had entered into 0.6 bcf of natural gas futures contracts (equivalent to approximately 102 GWh of energy contracts using a ratio of 6 MMBtu to 1 MWh) for the Midwest Generation plants to economically hedge energy price risks during 2010 at an equivalent average energy price of approximately $38.40/MWh.
The decline in 2010 market prices will impact realized energy and hedge prices in 2011 and 2012 and could have a material impact on 2011 and 2012 results.
Through October 25, 2010, offsetting positions were entered into to reduce the hedge position of EMG's merchant operations. The reduction in the hedge position was:
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The following table summarizes the status of capacity sales for Midwest Generation and Homer City at September 30, 2010:
October 1, 2010 to May 31, 2011
Midwest Generation
Homer City
June 1, 2011 to May 31, 2012
June 1, 2012 to May 31, 2013
June 1, 2013 to May 31, 2014
The RPM auction capacity prices for the delivery periods 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 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, which is uncertain.
During the nine months ended September 30, 2010, transmission congestion in PJM has resulted in prices at the individual busbars of the Midwest Generation plants being lower than those at the AEP/Dayton Hub and Northern Illinois Hub by an average of 10% and 1%, respectively, compared to 15% and less than 1%, respectively, during the nine months ended September 30, 2009. During the nine months ended September 30, 2010 and 2009, transmission congestion in PJM has resulted in prices at the Homer City busbar being lower than those at the PJM West Hub by an average of 15% and 9%, respectively.
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The Midwest Generation plants and Homer City facilities 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 September 30, 2010 for the remainder of 2010 and the following three 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 facilities, increased during 2010 from 2009 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 $69.50 per ton at October 1, 2010, compared to a price of $52.50 per ton at December 31, 2009, 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 increased during 2010 from 2009 year-end prices. The market price of PRB coal increased to a price of $14.75 per ton at October 1, 2010, compared to a price of $9.25 per ton at December 31, 2009, 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 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.
EMG purchases (or sells) emission allowances for the fossil-fueled facilities based on the amounts required for actual generation in excess of (or less than) the amounts allocated to these facilities under applicable programs. In the event that actual emission allowances 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 $49 per ton during the nine months ended September 30, 2010 from $65 per ton in 2009. The average purchase price of annual NOx allowances decreased to $936 per ton during the nine months ended September 30, 2010 from $1,431 per ton in 2009. Based on broker's quotes and information from public sources, the spot price for SO2 allowances and annual NOx allowances was $10.50 per ton and $335 per ton, respectively, at September 30, 2010.
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For a discussion of environmental regulations related to emissions, refer to "Environmental Regulation of Edison International and Subsidiaries" in the 2009 Form 10-K.
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 September 30, 2010, the balance sheet exposure as described above, broken down by the credit ratings of EMG's counterparties, was as follows:
Credit Rating1
Below investment grade
The credit risk exposure set forth in the above table is comprised of $128 million of net accounts receivable and payables and $224 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 an $89 million cash margin in the aggregate with PJM, New York Independent System Operator (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 fossil-fueled facilities sell electric power generally into the PJM market by participating in PJM's capacity and energy markets or transact in capacity and energy on a bilateral basis. Sales into PJM accounted for approximately 68% of EMG's consolidated operating revenues for the nine months ended September 30, 2010. Moody's rates PJM's debt Aa3. PJM, a regional transmission organization (RTO) with over 300 member companies, maintains its own credit risk policies and does not extend unsecured credit to non-investment grade companies. Losses resulting from a PJM member default are shared by all other members using a predetermined formula. At September 30, 2010, EMG's account receivable due from PJM was $52 million.
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The terms of EMG's wind turbine supply agreements contain significant obligations of the suppliers in the form of 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.
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 3. Liabilities and Lines of Credit." The fair market values of fixed interest rate obligations are subject to interest rate risk. The fair market value of EMG's consolidated construction loan and long-term obligations (including current portion) was $3.3 billion at September 30, 2010, compared to the carrying value of $4.2 billion.
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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 income (loss) from continuing operations were $6 million and $(3) million for the three months ended September 30, 2010 and 2009, respectively, and $18 million and $34 million for the nine months ended September 30, 2010 and 2009, respectively.
This section discusses Edison International (parent) and other cash flows from operating, financing and investing activities.
Cash flows used by operating activities
Cash flows provided by investing activities
Cash flows used by operating activities decreased $177 million primarily due to Global Settlement. During the nine months ended September 30, 2010, Edison International received $134 million in taxes related to Global Settlement and made tax allocation payments to SCE of $295 million. Also during this period, Edison International and Edison Capital agreed to offset tax obligations due by Edison Capital with intercompany loans due from Edison International (such intercompany loans have been settled in full). During the nine months ended September 2009, Edison International made tax payments of $343 million related to Global Settlement. During this period, Edison International received $1.2 billion in tax allocation payments, principally from Edison Capital (funded by the proceeds of termination of the cross-border leases), and made tax allocation payments to SCE of $875 million.
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Edison International's long-term principal debt maturities plus interest payments as of September 30, 2010 are estimated to be: $197 million for the remainder of 2010, $803 million in 2011, $753 million in 2012, $1.2 billion in 2013, $1.8 billion in 2014, and $17.9 billion for the period remaining thereafter. These amounts have been updated primarily to reflect SCE's and Edison International (parent) financing activities completed during 2010. For a discussion of issuances of long-term debt, see "Edison International Notes to Consolidated Financial Statements Note 3. Liabilities and Lines of Credit—Long-Term Debt."
For a discussion of Edison International (Consolidated) contractual obligations, refer to "Edison International (Consolidated)—Contractual Obligations" in the year-ended 2009 MD&A. There have been no other significant changes with respect to Edison International (Consolidated) contractual obligations since the filing of the 2009 Form 10-K, except as 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 policies, refer to "Edison International (Consolidated)—Critical Accounting Policies and Estimates" in the year-ended 2009 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.
There were no changes in Edison International's internal control over financial reporting (as that term is defined in Rules 13(a)-15(f) or 15(d)-15(f) under the Exchange Act) during the quarter to which this report relates that have materially affected, or are reasonably likely to materially affect, Edison International's internal control over financial reporting.
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Developments related to the Homer City New Source Review Notice of Violation are discussed in "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies—Homer City New Source Review Notice of Violation—Recent Developments."
Developments related to the Midwest Generation New Source Review Lawsuit are discussed in "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies—Midwest Generation New Source Review Lawsuit—Recent Developments."
EME and Mitsubishi Power Systems Americas, Inc. are parties to a wind turbine generator supply agreement executed in March 2007 with respect to the purchase of 166 wind turbines and related services and warranties. Mitsubishi has delivered 83 wind turbines under the agreement. As a result of a dispute between the parties, EME filed a complaint on March 19, 2010, and an amended complaint on April 1, 2010, in the Superior Court of the State of California against Mitsubishi Power Systems Americas, Inc. and Mitsubishi Heavy Industries, Ltd with respect to the agreement. The Mitsubishi entities filed counterclaims, including claims for the unpaid purchase price for the remaining turbines.
On October 8, 2010, EME and the Mitsubishi entities entered into a settlement agreement with respect to the dispute. As a result of the settlement agreement, EME's $68 million deposit previously paid under the original contract will be applied to the purchase price for 23 wind turbines (55 MW). Within the next three years, EME may elect to deploy 60 additional wind turbines (144 MW). EME 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. EME further agreed to payments up to $40 million for settlement of remaining disputes on turbines purchased.
Developments related to the Navajo Nation Litigation are discussed in "Edison International Notes to Consolidated Financial Statements Note 6. Commitments and Contingencies—Contingencies—Navajo Nation Litigation."
In May 2010, the California Coastal Commission issued a 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 the NOV, the Coastal Commission indicated an interest in negotiating a settlement of the alleged violations but no specific settlement terms have been proposed nor has a settlement been reached. The Coastal Act provides for penalties of up to $30,000 per
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violation, which may be increased by up to $15,000 per day per violation for knowing and intentional violations. SCE has sought indemnification from its contractor for liability associated with the NOV.
July 1, 2010 to July 31, 2010
August 1, 2010 to August 31, 2010
September 1, 2010 to September 30, 2010
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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.
Date: October 29, 2010
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