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Edison International 10-Q 2008 Table of Contents
UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549
FORM 10-Q
(Mark One)
Commission File Number 1-9936
EDISON INTERNATIONAL (Exact name of registrant as specified in its charter)
(626) 302-2222 (Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer” in Rule 12b-2 of the Exchange Act.
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date:
Table of ContentsINDEX
Table of ContentsGLOSSARY When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.
Table of ContentsGLOSSARY (Continued)
Table of ContentsPART I FINANCIAL INFORMATION Item 1. Financial Statements CONSOLIDATED STATEMENTS OF INCOME
The accompanying notes are an integral part of these consolidated financial statements.
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Table of ContentsCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
The accompanying notes are an integral part of these consolidated financial statements.
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Table of ContentsCONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
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Table of ContentsEDISON INTERNATIONAL CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
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Table of ContentsCONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
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Table of ContentsEDISON INTERNATIONAL CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
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Table of ContentsNOTES TO CONSOLIDATED FINANCIAL STATEMENTS Management’s Statement 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 six-month periods ended June 30, 2008 are not necessarily indicative of the operating results for the full year. This quarterly report should be read in conjunction with Edison International’s Annual Report to Shareholders incorporated by reference into Edison International’s Annual Report on Form 10-K for the year ended December 31, 2007 filed with the Securities and Exchange Commission. Note 1. Summary of Significant Accounting Policies Basis of Presentation Edison International’s significant accounting policies were described in Note 1 of “Notes to Consolidated Financial Statements” included in its 2007 Annual Report on 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, 2008 as discussed below in “Margin and Collateral Deposits” and “New Accounting Pronouncements.” Certain prior-year reclassifications have been made to conform to the current year financial statement presentation mostly pertaining to the adoption of FIN No. 39-1. Except as indicated, amounts presented in the Notes to the Consolidated Financial Statements relate to continuing operations.
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Table of ContentsEarnings Per Common 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 2002 and after 2006 were granted without a dividend equivalent feature. As a result of meeting a performance trigger, the options granted in 1998 and 1999 began earning dividend equivalents in 2006. EPS was computed as follows:
Stock-based compensation awards to purchase 108,901 and 2,500 shares of common stock for the three months ended June 30, 2008 and 2007, respectively, and 108,901 and 25,000 shares of common stock for the six months ended June 30, 2008 and 2007, 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; therefore, the effect would have been antidilutive. Intangible Assets The caption “Other current assets” on Edison International’s consolidated balance sheets includes emission allowances purchased for use by EME of $41 million and $45 million at June 30, 2008 and December 31, 2007, respectively. The caption “Other long-term assets” on Edison International’s consolidated balance sheets includes EME’s project development rights, option rights, and purchased emission allowances and the total amounted to $108 million and $61 million, at June 30, 2008 and December 31, 2007, respectively.
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Table of ContentsBased on the CAIR requirements, Midwest Generation purchased $48 million of annual NOX allowances under the new CAIR annual NOX program which was vacated by the District of Columbia Circuit Court of Appeals in July 2008. As a result of this decision, the annual NOX allowances may no longer be required. Midwest Generation is currently evaluating the above decision including whether the purchased annual NOx allowances are impaired which could result in a charge against income during the third quarter ending September 30, 2008. Margin and Collateral Deposits Margin and collateral deposits include margin requirements and cash deposited with and received from counterparties and brokers as credit support under energy contracts. The amount of margin and collateral deposits generally varies based on changes in the fair value of the related positions. See “New Accounting Pronouncements” below for a discussion of the adoption of FIN No. 39-1. In accordance with FIN No. 39-1, Edison International presents a portion of its margin and cash collateral deposits net with its derivative positions on its consolidated balance sheets. Amounts recognized for cash collateral provided to others that have been offset against net derivative liabilities totaled $226 million and $38 million at June 30, 2008 and December 31, 2007, respectively. Amounts recognized for cash collateral received from others that have been offset against net derivative assets totaled $23 million at June 30, 2008. New Accounting Pronouncements Accounting Pronouncements Adopted In April 2007, the FASB issued FIN No. 39-1. This pronouncement permits companies to offset fair value amounts recognized for the right to reclaim cash collateral (a receivable) or the obligation to return cash collateral (a payable) against fair value amounts recognized for derivative instruments executed with the same counterparty under a master netting arrangement. In addition, upon the adoption, companies were permitted to change their accounting policy to offset or not offset fair value amounts recognized for derivative instruments under master netting agreements. Edison International adopted FIN No. 39-1 effective January 1, 2008. The adoption resulted in netting a portion of margin and cash collateral deposits with derivative positions on Edison International’s consolidated balance sheets, but had no impact on its consolidated statements of income. The consolidated balance sheet at December 31, 2007 has been retroactively restated for the change, which resulted in a decrease in net assets (margin and collateral deposits) of $38 million. The consolidated statements of cash flows for the six months ended June 30, 2007 has been retroactively restated to reflect the balance sheet changes, which had no impact on total operating cash flows from continuing operations. In February 2007, the FASB issued SFAS No. 159, which provides an option to report eligible financial assets and liabilities at fair value, with changes in fair value recognized in earnings. Edison International adopted this pronouncement effective January 1, 2008. The adoption had no impact because Edison International did not make an optional election to report additional financial assets and liabilities at fair value. In September 2006, the FASB issued SFAS No. 157, which clarifies the definition of fair value, establishes a framework for measuring fair value and expands the disclosures on fair value measurements. Edison International adopted SFAS No. 157 effective January 1, 2008. The adoption did not result in any retrospective adjustments to its consolidated financial statements. The accounting requirements for employers’ pension and other postretirement benefit plans are effective at the end of 2008, which is the next measurement date for these benefit plans. The effective date will be January 1, 2009 for asset retirement obligations and other nonfinancial assets and liabilities which are measured or disclosed on a non-recurring basis. For further discussion, see Note 8. Accounting Pronouncements Not Yet Adopted In December 2007, the FASB issued SFAS No. 141(R), which establishes principles and requirements for how the acquirer in a business combination recognizes and measures in its financial statements the identifiable assets
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Table of Contentsacquired, the liabilities assumed and any noncontrolling interest in the acquiree at the acquisition date fair value. SFAS No. 141(R) determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141(R) applies prospectively to business combinations for which the acquisition date is on or after fiscal years beginning on or after January 1, 2009. Early adoption is not permitted. In December 2007, the FASB issued SFAS No. 160, which requires an entity to present minority interest that reflects the ownership interests in subsidiaries held by parties other than the entity, within the equity section but separate from the entity’s equity in the consolidated financial statements. It also requires the amount of consolidated net income attributable to the parent and to the noncontrolling interest to be clearly identified and presented on the face of the consolidated statement of income; changes in ownership interest be accounted for similarly as equity transactions; and, when a subsidiary is deconsolidated, any retained noncontrolling equity investment in the former subsidiary and the gain or loss on the deconsolidation of the subsidiary be measured at fair value. Edison International will adopt SFAS No. 160 on January 1, 2009. In accordance with this standard, Edison International will reclassify minority interest to a component of shareholders’ equity (at June 30, 2008 this amount was $314 million). In March 2008, the FASB issued SFAS No. 161, which requires additional disclosures related to derivative instruments, including how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for and how derivative instruments and related hedged items affect an entity’s financial position, financial performance, and cash flows. SFAS No. 161 is effective for fiscal years beginning after November 15, 2008, with early adoption permitted. Edison International will adopt SFAS No. 161 in the first quarter of 2009. SFAS No. 161 will impact disclosures only and will not have an impact on Edison International’s consolidated results of operations, financial condition or cash flows. In April 2008, the FASB issued FSP FAS No. 142-3 which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The intent of the position is to improve the consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of the asset under SFAS No. 141(R) and other U.S. generally accepted accounting principles. Edison International will adopt FSP FAS No. 142-3 on January 1, 2009. Edison International is currently evaluating the impact, if any, that the adoption of this position could have on its consolidated financial statements. Property and Plant Utility Plant Utility plant additions, including replacements and betterments, are capitalized. Such costs include direct material and labor, construction overhead, a portion of administrative and general costs capitalized at a rate authorized by the CPUC, and AFUDC. AFUDC represents the estimated cost of debt and equity funds that finance utility-plant construction. Currently, AFUDC debt and equity is capitalized during certain plant construction and reported in interest expense and other nonoperating income, respectively. AFUDC is recovered in rates through depreciation expense over the useful life of the related asset. On November 26, 2007, the FERC issued an order granting incentives on three of SCE’s largest proposed transmission projects, DPV2, Tehachapi Transmission Project (“Tehachapi”), and Rancho Vista Substation Project (“Rancho Vista”). The order permits SCE to include in rate base 100% of prudently-incurred capital expenditures during construction of all three projects. On February 29, 2008, the FERC approved SCE’s revision to its Transmission Owner Tariff to collect 100% of construction work in progress (CWIP) for these projects in rate base and earn a return on equity, rather than capitalizing AFUDC. SCE implemented the CWIP rate, subject to refund, on March 1, 2008. For further discussion, see “FERC Transmission Incentives” in Note 5.
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Table of ContentsRelated Party Transactions During the first quarter of 2008, a subsidiary of EME was awarded, through a competitive bidding process, a ten-year power sales contract with SCE for the output of a 479 MW gas-peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. The power sales agreement is subject to approval of the CPUC which SCE requested on April 4, 2008. CPUC approval is expected to be granted by late 2008. As an affiliate transaction, the contract is also subject to FERC approval, which was requested on May 2, 2008. Deliveries under the power sales agreement are expected to commence in 2013. Short-term Investments At June 30, 2008 and December 31, 2007, Edison International classified all marketable debt securities as held-to-maturity. The securities were carried at amortized cost plus accrued interest which approximated their fair value. Gross unrealized holding gains and losses were not material. Edison International’s held-to-maturity securities, which all mature within one year, consisted of the following:
Note 2. Liabilities and Lines of Credit Long-Term Debt In January 2008, SCE issued $600 million of 5.95% first and refunding mortgage bonds due in 2038. The proceeds were used to repay SCE’s outstanding commercial paper of approximately $426 million and for general corporate purposes. The interest rates on one issue of SCE’s pollution control bonds insured by FGIC, totaling $249 million, were reset every 35 days through an auction process. Due to a loss of confidence in the creditworthiness of the bond insurers, there was a significant reduction in market liquidity for auction rate bonds and interest rates on these bonds increased. Consequently, SCE purchased in the secondary market $37 million of its auction rate bonds in December 2007. In the first three months of 2008, SCE purchased the remaining $212 million of its auction rate bonds, converted the issue to a variable rate mode, and terminated the FGIC insurance policy. SCE continues to hold the bonds which remain outstanding and have not been retired or cancelled. Short-Term Debt SCE’s short-term debt is generally used to finance fuel inventories, balancing account undercollections and general, temporary cash requirements including power-purchase payments. At June 30, 2008, the outstanding short-term debt was $800 million at a weighted-average interest rate of 2.58%. SCE’s short-term debt is supported by a $2.5 billion credit line. See below in “Credit Agreement Amendments.” Credit Agreement Amendments On March 12, 2008, both Edison International and SCE amended their existing credit facilities, extending the maturities to February 2013 while retaining existing borrowing costs as specified in the facilities. The
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Table of Contentsamendments also provide four extension options which, if all exercised, will result in final terminations in February 2017. At June 30, 2008, SCE’s $2.5 billion credit facility supported $197 million in letters of credit and $800 million of short-term debt outstanding, leaving $1.5 billion available for liquidity purposes. At June 30, 2008, all of Edison International’s (parent) $1.5 billion credit facility was available for liquidity purposes. Note 3. Income Taxes Edison International’s composite federal and state statutory income tax rate was approximately 40% (net of the federal benefit for state income taxes) for all periods presented. Edison International’s effective tax rate was 24% and 30% for the three- and six-month periods ended June 30, 2008, respectively, as compared to 0% and 23% for the respective periods in 2007. The increased effective tax rates in 2008, as compared to 2007, were primarily due to reductions at SCE during 2007, as discussed below. The higher effective tax rates were partially offset by SCE internally developed software flow-through tax deductions recorded in 2008. The effective tax rates in 2007 were lower than the statutory rate primarily due to progress made in the first quarter of 2007 in an administrative appeal process with the IRS related to the income tax treatment of certain of SCE’s costs associated with environmental remediation; reductions made at SCE during the second quarter of 2007 to reflect receipt of a state Notice of Proposed Adjustment; and also due to property related flow-through items at SCE. In addition, the decreased effective tax rate in the second quarter of 2007 resulted from a reduction in pre-tax income. Accounting for Uncertainty in Income Taxes FIN 48 requires an enterprise to recognize, in its financial statements, the best estimate of the impact of a tax position by determining if the weight of the available evidence indicates it is more likely than not, based solely on the technical merits, that the position will be sustained on audit. Edison International has filed affirmative tax claims related to tax positions, which, if accepted, could result in refunds of taxes paid or additional tax benefits for positions not reflected on filed original tax returns. FIN 48 requires the disclosure of all unrecognized tax benefits, which includes the reserves recorded for tax positions on filed tax returns and the unrecognized portion of affirmative claims. Unrecognized Tax Benefits Tabular Disclosure The following table provides a reconciliation of unrecognized tax benefits from January 1, 2008 to June 30, 2008:
The unrecognized tax benefits in the table above reflects affirmative claims related to timing differences of $1.5 billion and $1.6 billion at June 30, 2008 and January 1, 2008, respectively, but have not met the recognition threshold pursuant to FIN 48 and have been denied by the IRS as part of their examinations. These affirmative claims remain unpaid by the IRS and no receivable has been recorded. Edison International is vigorously defending these affirmative claims in IRS administrative appeals proceedings.
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Table of ContentsIt is reasonably possible that Edison International could reach a settlement with the IRS for all or a portion of the unrecognized tax benefits through tax year 2002 within the next 12 months, which could reduce unrecognized tax benefits by up to $1.3 billion. The total amount of unrecognized tax benefits as of June 30, 2008 and January 1, 2008 that, if recognized, would have an effective tax rate impact is $205 million and $206 million, respectively. The total amount of accrued interest and penalties were $184 million and $162 million as of June 30, 2008 and January 1, 2008, respectively. The after-tax interest expense recognized and included in income tax expense was $5 million and $13 million for the three- and six-month periods ended June 30, 2008, respectively. Tax Positions being addressed as part of active examinations and administrative appeals processes Edison International is challenging certain IRS deficiency adjustments for tax years 1994 – 1999 with the Administrative Appeals branch of the IRS and Edison International is currently under active IRS examination for tax years 2000 – 2002. In addition, the statute of limitations remains open for tax years 1986 – 1993, which has allowed Edison International to file certain affirmative claims related to these tax years. Most of these tax positions relate to timing differences and, therefore, any amounts that would be paid if Edison International’s position is not sustained (exclusive of any penalties) would be deductible on future tax returns filed by Edison International. In addition, Edison International has filed affirmative claims with respect to certain tax years 1986 through 2005 with the IRS and state tax authorities. Any benefits associated with these affirmative claims would be recorded in accordance with FIN 48 which provides that recognition would occur at the earlier of when Edison International would make an assessment that the affirmative claim position has a more likely than not probability of being sustained or when a settlement of the affirmative claim is consummated with the tax authority. Certain of these affirmative claims have been recognized as part of the implementation of FIN 48. Currently, Edison International is under administrative appeals with the California Franchise Tax Board for tax years 1997 – 2002 and under examination for tax years 2003 – 2004. Edison International remains subject to examination by the California Franchise Tax Board for tax years 2005 and forward. Edison International is also subject to examination by other state tax authorities, subject to varying statute of limitations. Edison International filed amended California Franchise Tax returns for tax years 1997 – 2002 to mitigate the possible imposition of new California penalty provisions on transactions that may be considered as listed or substantially similar to listed transactions described in an IRS notice that was published in 2001. These transactions include certain Edison Capital leveraged lease transactions and the SCE subsidiary contingent liability company transaction, described below. Edison International filed these amended returns under protest retaining its appeal rights. Balancing Account Over-Collections In response to an affirmative claim related to balancing account over-collections, Edison International received an IRS Notice of Proposed Adjustment in July 2007. This affirmative claim is part of the ongoing IRS examinations and administrative appeals process and all of the tax years included in this Notice of Proposed Adjustment remain subject to ongoing examination and administrative appeals. The cash and earnings impacts of this position are dependent on the ultimate settlement of all open tax issues in these tax years. Edison International expects that resolution of this particular issue could potentially increase earnings and cash flows within the range of $70 million to $80 million and $300 million to $350 million, respectively. Contingent Liability Company The IRS has asserted deficiencies with respect to a transaction entered into by a former SCE subsidiary which may be considered substantially similar to a listed transaction described by the IRS as a contingent liability
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Table of Contentscompany for tax years 1997 – 1998. This is being considered by the Administrative Appeals branch of the IRS where Edison International is defending its tax return position with respect to this transaction. Lease Transactions As part of a nationwide challenge of cross border lease transactions, the IRS has asserted deficiencies related to Edison International’s deferral of income taxes associated with certain of its cross-border, leveraged leases. For tax years 1994 – 1999, Edison International is challenging the asserted deficiencies in ongoing IRS Appeals proceedings. These asserted deficiencies relate to Edison Capital’s income tax treatment of both its foreign power plant and electric locomotive sale/leaseback transactions entered into in 1993 and 1994 (Replacement Leases, which the IRS refers to as sale-in/lease-out or SILOs) and its foreign power plants and electric transmission system lease/leaseback transactions entered into in 1997 and 1998 (Lease/Leaseback, which the IRS refers to as lease-in/lease-out or LILOs). In 1999, Edison Capital entered into a lease/service contract transaction involving a foreign telecommunication system (Service Contract, which the IRS refers to as a SILO). As part of an ongoing examination of 2000 – 2002, the IRS is reviewing Edison International’s income tax treatment of this Service Contract and has issued several data requests, to which Edison International has responded. The IRS has not formally asserted any adjustments, but Edison International believes that the IRS examination team will assert deficiencies related to this Service Contract. The following table summarizes estimated federal and state income taxes deferred from these leases as of December 31, 2007. Repayment of these deferred taxes would be accelerated if the IRS position were to be sustained:
As of June 30, 2008, the interest (after tax) on the proposed tax adjustments is estimated to be approximately $590 million. The IRS has also asserted a 20% penalty on any sustained adjustment. During the second quarter of 2008, several court developments addressing income taxation of cross-border leveraged leases occurred. The court developments represent increased uncertainty about the tax treatment of SILOs and LILOs generally. Despite these developments, Edison International believes it properly reported these transactions based on applicable statutes, regulations and case law and, in the absence of any settlement with the IRS, will continue to vigorously defend its tax treatment of these leases. Recent developments, however, underscore the uncertain nature of tax conclusions in this area. Edison International believes that its maximum earnings exposure related to these leases, measured as of June 30, 2008, is approximately $1.25 billion after taxes, calculated by reclassifying deferred income taxes to current,
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Table of Contentsrecomputing the cumulative earnings under the leases in accordance with lease accounting rules (FASB Staff Position FAS 13-2), and recording interest related to the current income tax liability. This exposure does not include IRS asserted penalties of 20%, as Edison International does not believe that even if the tax benefits taken by Edison Capital are successfully challenged by the IRS that these penalties would be sustained. The current and future income and cash positions of SCE and EME are virtually unaffected by these leases. Edison International will continue to monitor and evaluate its lease transactions with respect to future events. Future adverse developments, including further adverse case law developments, could change Edison International’s current conclusions. As previously disclosed, Edison International has been engaged in settlement negotiations with the IRS. These negotiations seek to resolve the lease issues in their entirety and all other outstanding tax disputes for the years 1994 through 2002, including certain affirmative claims for unrecognized tax benefits. These negotiations have progressed to the point where Edison International and the IRS have reached nonbinding, preliminary understandings on the material principles for resolving such tax disputes on a “global” basis, including the lease issues. Final resolution of such disputes, however, is subject to reaching definitive agreements on final terms and calculations, mutually satisfactory documentation, and review of all or a portion of such settlements by the Staff of the Joint Committee on Taxation, a committee of the United States Congress (the “Joint Committee”). Were Edison International and the IRS to implement the preliminary understanding regarding the leases, Edison International anticipates that it will be required to terminate the leases as an interim step in the implementation of the overall settlement before executing final agreements with the IRS and before review by the Joint Committee. Edison Capital and its subsidiaries have executed term sheets with the counterparties to its SILOs and LILOs which contemplate termination of the leases subject to the parties agreeing to and executing definitive agreements and to a final settlement agreement with the IRS. Upon termination of the leases, the lessees would be required to make termination payments from certain collateral deposits associated with the leases. Termination of the leases, which may occur in 2008, would result in Edison International recording an after-tax charge to earnings currently estimated to be at least $650 million, and potentially up to the maximum earnings exposure indicated above. If all settlements included in the global settlement discussions were ultimately concluded consistent with the preliminary understandings, Edison International would expect that the settlement of the disputed lease issues and the resolution of the above-mentioned affirmative claims would result in a portion of the charge initially recorded upon termination of the leases being offset and/or reduced, and the net after-tax earnings charge that would remain is currently expected to be less than half of the maximum after-tax earnings exposure, calculated as of June 30, 2008, discussed above. Were all settlements completed in a manner consistent with the preliminary understandings, the net cash impact upon Edison International as a whole of the settlements and lease terminations would be positive over time, and it is not anticipated that borrowings would be required in connection with implementation of the settlements. There can be no assurance, however, about the timing of final settlements with the IRS or that such final settlements will be ultimately consummated. Moreover, even if final settlements are reached with the IRS, review by the Joint Committee could result in adjustments. The IRS and Edison International may not reach final agreements that implement the preliminary understandings, or they may reach final agreements but conditions to consummating them may not be satisfied. If Edison International terminated the SILO and LILO leases without consummating the settlements, then it could not seek through litigation with the IRS future deferred tax benefits that may have been otherwise available in the absence of termination. To the extent that an acceptable settlement is not reached with the IRS, Edison International will continue to vigorously defend its tax treatment of the leases and is prepared to take legal action. If Edison International were
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Table of Contentsto commence litigation in certain forums, it would need to make payments of the disputed taxes, along with interest and any penalties asserted by the IRS, and thereafter pursue refunds. In the other litigation forum (the Tax Court), no upfront payment would be required. In 2006, Edison International paid $111 million of the taxes, interest and penalties for tax year 1999 followed by a refund claim for the same amount. The IRS did not act on this refund claim within the statutory six month period, which provides Edison International with the option of being able to take legal action to assert its refund claim. To the extent an acceptable settlement is not reached with the IRS, Edison International would expect to file a refund claim for any taxes and penalties paid for the 1994 – 1996 tax years related to the leases. Edison International has not decided whether and to what extent it would make additional payments related to later tax years to fund its right to litigate in certain forums should the global settlement discussed above not be consummated. Resolution of Federal and State Income Tax Issues Being Addressed in Ongoing Examinations and Administrative Appeals Edison International continues its efforts to resolve open tax issues through tax year 2002. Although the timing for resolving these open tax positions is uncertain, it is reasonably possible that all or a significant portion of these open tax issues through tax year 2002 could be resolved within the next 12 months. Note 4. Compensation and Benefits Plans Pension Plans As of June 30, 2008, Edison International had made $7 million in contributions related to 2007 and $31 million related to 2008 and estimates to make $26 million of additional contributions in the last six months of 2008. Expected contribution funding in 2008 could vary from anticipated amounts, depending on the funded status at year-end and tax-deductible funding limitations. Net pension cost recognized is calculated under the actuarial method used for ratemaking. The difference between pension costs calculated for accounting and ratemaking is deferred. Expense components are:
Postretirement Benefits Other Than Pensions As of June 30, 2008, Edison International had made no contributions related to 2007 and $11 million related to 2008 and estimates to make $43 million of additional contributions in the last six months of 2008. Expected contribution funding in 2008 could vary from anticipated amounts, depending on the funded status at year-end and tax-deductible funding limitations.
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Table of ContentsExpense components are:
Stock-Based Compensation During the first quarter of 2008, Edison International granted its 2008 stock-based compensation awards, which included stock options, performance shares, deferred stock units and restricted stock units. Total stock-based compensation expense (reflected in the caption “Other operation and maintenance” on the consolidated statements of income) was $12 million and $22 million for the three months ended June 30, 2008 and 2007, respectively, and was $19 million and $29 million for the six months ended June 30, 2008 and 2007, respectively. The income tax benefit recognized in the consolidated statements of income was $5 million and $9 million for the three months ended June 30, 2008 and 2007, respectively, and was $8 million and $12 million for the six months ended June 30, 2008 and 2007, respectively. Total stock-based compensation cost capitalized was $1 million and $2 million for the three months ended June 30, 2008 and 2007, respectively, and was $2 million and $3 million for the six months ended June 30, 2008 and 2007, respectively. Stock Options A summary of the status of Edison International stock options is as follows:
Stock options granted in 2008 do not accrue dividend equivalents. The amount of cash used to settle stock options exercised was $27 million and $77 million for the three months ended June 30, 2008 and 2007, respectively, and was $40 million and $163 million for the six months ended June 30, 2008 and 2007, respectively. Cash received from options exercised was $13 million and $33 million for the three months ended June 30, 2008 and 2007, respectively, and was $20 million and $72 million for the six
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Table of Contentsmonths ended June 30, 2008 and 2007, respectively. The estimated tax benefit from options exercised was $5 million and $18 million for the three months ended June 30, 2008 and 2007, respectively, and was $8 million and $36 million for the six months ended June 30, 2008 and 2007, respectively. Note 5. Commitments and Contingencies The following is an update to Edison International’s commitments and contingencies. See Note 6 of “Notes to Consolidated Financial Statements” included in Edison International’s 2007 Annual Report on Form 10-K for a detailed discussion. Lease Commitments During the second quarter of 2008, SCE entered into power-purchase contracts which are classified as operating leases. The contract terms range from 10 to 40 years. The delivery of energy under one of these contracts is not expected to commence until 2018. These additional commitments are currently estimated to be: remainder of 2008 – $27 million, 2009 – $48 million, 2010 – $48 million, 2011 – $48 million, 2012 – $48 million and thereafter – $1.9 billion. Other Commitments During the first six months of 2008, SCE entered into service contracts associated with uranium enrichment and fuel fabrication. As a result, SCE’s additional fuel supply commitments are estimated to be: remainder of 2008 – $15 million, 2009 – $49 million, 2010 – $50 million, 2011 – $96 million, 2012 – $141 million and thereafter – $665 million. During the second quarter of 2008, SCE entered into a new power-purchase contract. The delivery of energy under this contract is expected to commence in August 2010 with a 10 year term. SCE’s additional commitments upon commencement are estimated to be: 2010 – $188 million, 2011 – $335 million, 2012 – $341 million and thereafter – $2.7 billion. At June 30, 2008, EME’s subsidiaries had firm commitments to spend approximately $259 million during the remainder of 2008 on capital and construction expenditures. The majority of these expenditures relate to the construction of wind projects. These expenditures are planned to be financed by cash on hand, cash generated from operations or existing subsidiary credit agreements. EME had entered into various turbine supply agreements with vendors to support its wind and thermal development efforts. At June 30, 2008, EME had secured 533 wind turbines (1,061 MW) and 5 gas-fired turbines (479 MW) for use in future projects for an aggregate purchase price of $1.6 billion, with remaining commitments of $407 million in 2008, $557 million in 2009 and $300 million in 2010. At June 30, 2008, EME had recorded wind turbine deposits of $294 million included in other long-term assets in its consolidated balance sheet. In connection with the acquisition of the Illinois Plants, Midwest Generation had assumed a long-term coal supply contract and recorded a liability to reflect the fair value of this contract. In March 2008, Midwest Generation entered into an agreement to buyout its coal obligations for the years 2009 through 2012 under this contract with a one-time payment to be made in January 2009. Midwest Generation recorded a pre-tax gain of $15 million ($9 million after tax) during the first quarter of 2008. The remaining payments due under this contract are $18 million. EME’s subsidiaries had entered into contractual agreements during the first six months of 2008 to purchase materials for environmental controls equipment. These commitments are currently estimated to be $188 million, summarized as follows: remainder of 2008 – $7 million, 2009 – $29 million, 2010 – $45 million, 2011 – $45 million, 2012 – $43 million and thereafter – $19 million.
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Table of ContentsGuarantees and Indemnities Edison International’s subsidiaries have various financial and performance guarantees and indemnifications which are issued in the normal course of business. As discussed below, these contracts included performance guarantees, guarantees of debt and indemnifications. Tax Indemnity Agreements 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. EME has not recorded a liability related to these indemnities. Indemnities Provided as Part of the Acquisition of the Illinois Plants In connection with the acquisition of the Illinois 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. Due to the nature of the obligation under this indemnity, a maximum potential liability cannot be determined. This indemnification for environmental liabilities is not limited in term and would be triggered by a valid claim from Commonwealth Edison. By letter dated August 8, 2007, Commonwealth Edison 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 NOV discussed below under “Midwest Generation New Source Review Notice of Violation.” By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification to EME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if the environmental groups were to file suit. Except as discussed below, EME has not recorded a liability related to this indemnity. 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 2009. Payments are made under this indemnity upon tender by Commonwealth Edison of appropriate proof of liability for an asbestos-related settlement, judgment, verdict, or expense. There were approximately 230 cases for which Midwest Generation was potentially liable and that had not been settled and dismissed at June 30, 2008. Midwest Generation had recorded a $53 million liability at June 30, 2008 related to this matter.
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Table of ContentsThe 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. Indemnity Provided as Part of the Acquisition of the Homer City Facilities In connection with the acquisition of the Homer City facilities, EME Homer City agreed to indemnify the sellers with respect to specific 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 the obligations of EME Homer City. 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. EME has not recorded a liability related to this indemnity. Indemnities Provided under Asset Sale 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 June 30, 2008, EME had recorded a liability of $108 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. At June 30, 2008, EME had recorded a liability of $12 million related to these matters. Capacity Indemnification Agreements EME has guaranteed, jointly and severally with Texaco Inc., the obligations of March Point Cogeneration Company under its project power sales agreements to repay capacity payments to the project’s power purchaser in the event that the power sales agreements terminate, March Point Cogeneration Company abandons the project, or the project fails to return to normal operations within a reasonable time after a complete or partial shutdown, during the term of the power sales agreements. The obligations under this indemnification agreement as of June 30, 2008, if payment were required, would be $66 million. EME has not recorded a liability related to this indemnity. Indemnity Provided as Part of the Acquisition of Mountainview In connection with the acquisition of Mountainview, 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.
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Table of ContentsMountainview Filter Cake Indemnity Mountainview owns and operates a power plant in Redlands, California. The 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, this water 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 CEC permit. Mountainview 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 guarantee. Other Edison International Indemnities Edison International provides other indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, and specified environmental indemnities and income taxes with respect to assets sold. Edison International’s obligations under these agreements may be limited in terms of time and/or amount, and in some instances Edison International may have recourse against third parties for certain indemnities. The obligated amounts of these indemnifications often are not explicitly stated, and the overall maximum amount of the obligation under these indemnifications cannot be reasonably estimated. Edison International has not recorded a liability related to these indemnities. Contingencies In addition to the matters disclosed in these Notes, Edison International is involved in other legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. Edison International believes the outcome of these other proceedings will not materially affect its consolidated results of operations or liquidity. Environmental Remediation Edison International is subject to numerous environmental laws and regulations, which 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. Edison International believes that it is in substantial compliance with environmental regulatory requirements; however, possible future developments, such as the enactment of more stringent environmental laws and regulations, could affect the costs and the manner in which business is conducted and could cause substantial additional capital expenditures. There is no assurance that additional costs would be recovered from customers or that Edison International’s consolidated financial position and results of operations would not be materially affected. 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 (classified as other long-term liabilities) at undiscounted amounts.
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Table of ContentsAs of June 30, 2008, Edison International’s recorded estimated minimum liability to remediate its 44 identified sites at SCE (24 sites) and EME (20 sites primarily related to Midwest Generation) was $64 million, $59 million of which was related to SCE including $24 million related to San Onofre. This remediation liability is undiscounted. 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 could exceed its recorded liability by up to $155 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 30 immaterial sites whose total liability ranges from $3 million (the recorded minimum liability) to $9 million. The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $33 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 $56 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. Edison International 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 $11 million to $31 million. Recorded costs for the 12 months ended June 30, 2008 were $25 million. 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 consolidated results of operations or financial position. 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 As part of a nationwide challenge of certain types of lease transactions, the IRS has raised issues about the deferral of income taxes associated with certain lease and kind of lease transactions. See Note 3 for further details. FERC Transmission Incentives On November 16, 2007, the FERC issued an order granting incentives on three of SCE’s largest proposed transmission projects:
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The order also grants a higher return on equity on SCE’s entire transmission rate base in SCE’s next FERC transmission rate case for SCE’s participation in the CAISO. On August 1, 2008, SCE filed a revision to its Transmission Owner Tariff with a requested effective date of October 1, 2008. In addition, the order permits SCE to include in rate base 100% of prudently-incurred capital expenditures during construction, also known as CWIP, of all three projects and 100% recovery of prudently-incurred abandoned plant costs for DPV2 and Tehachapi, if either or both of these projects are cancelled due to factors beyond SCE’s control. FERC Construction Work in Progress Mechanism On December 21, 2007, SCE filed a revision to its Transmission Owner Tariff to collect 100% of CWIP in rate base for its Tehachapi, DPV2, and Rancho Vista projects. In the CWIP filing, SCE proposed a single-issue rate adjustment ($45 million or a 14.4% increase) to SCE’s currently authorized base transmission revenue requirement to be made effective on March 1, 2008 and later adjusted for amounts actually spent in 2008 through a new balancing account mechanism. The rate adjustment represents actual expenditures from September 1, 2005 through November 30, 2007, projected expenditures from December 1, 2007 through December 31, 2008, and a ROE (which includes the ROE adders approved for Tehachapi, DPV2 and Rancho Vista). SCE projects that it will spend a total of approximately $244 million, $27 million, and $181 million for Tehachapi, DPV2, and Rancho Vista, respectively, from September 1, 2005 through the end of 2008. The 2008 DPV2 expenditure forecast is limited to projected consulting and legal costs associated with SCE’s continued efforts to obtain regulatory approvals necessary to construct the DPV2 Project. On February 29, 2008, the CWIP filing was approved and SCE implemented the CWIP rate on March 1, 2008, subject to refund on the limited issue of whether SCE’s proposed ROEs are reasonable. On March 28, 2008, the CPUC filed a Petition for Rehearing with the FERC on the FERC’s acceptance of SCE’s proposed ROE for CWIP. Briefs addressing the appropriate ROE were filed by SCE and intervenors in May 2008. In addition, in the order, SCE was directed by FERC to make a compliance filing to provide greater detail on the costs reflected in CWIP rates for 2008. SCE made the compliance filing on March 31, 2008. On April 21, 2008, the CPUC filed a protest of the compliance filing at FERC and requested an evidentiary hearing to be set to further review the costs. SCE filed a response to the CPUC’s protest on May 6, 2008 arguing that the FERC should deny the CPUC’s request for a further hearing. SCE cannot predict the outcome of the matters in this proceeding. Investigations Regarding Performance Incentives Rewards SCE was eligible under its CPUC-approved PBR mechanism to earn rewards or penalties based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and illness reporting, and system reliability. SCE conducted investigations into its performance under these PBR mechanisms and has reported to the CPUC certain findings of misconduct and misreporting as further discussed below. Customer Satisfaction SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service planning group of SCE’s transmission and distribution business unit altered or omitted data in attempts to influence the outcome of customer satisfaction surveys conducted by an independent survey organization. The
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Table of Contentsresults of these surveys are used, along with other factors, to determine the amounts of any incentive rewards or penalties for customer satisfaction. SCE recorded aggregate customer satisfaction rewards of $28 million over the period 1997 – 2000. Potential customer satisfaction rewards aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE also anticipated that it could be eligible for customer satisfaction rewards of approximately $10 million for 2003. Following its internal investigation, SCE proposed to refund to ratepayers $7 million of the PBR rewards previously received and forgo an additional $5 million of the PBR rewards pending that are both attributable to the design organization’s portion of the customer satisfaction rewards for the entire PBR period (1997 – 2003). In addition, SCE also proposed to refund all of the approximately $2 million of customer satisfaction rewards associated with meter reading. SCE has taken remedial action as to the customer satisfaction survey misconduct by disciplining employees and/or terminating certain employees, including several supervisory personnel, updating system process and related documentation for survey reporting, and implementing additional supervisory controls over data collection and processing. Performance incentive rewards for customer satisfaction expired in 2003 pursuant to the 2003 GRC. Employee Injury and Illness Reporting In light of the problems uncovered with the customer satisfaction surveys, SCE conducted an investigation into the accuracy of SCE’s employee injury and illness reporting. The yearly results of employee injury and illness reporting to the CPUC are used to determine the amount of the incentive reward or penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has recognized $20 million in employee safety incentives for 1997 through 2000 and, based on SCE’s records, may be entitled to an additional $15 million for 2001 through 2003. On October 21, 2004, SCE reported to the CPUC and other appropriate regulatory agencies certain findings concerning SCE’s performance under the PBR incentive mechanism for injury and illness reporting. SCE disclosed in the investigative findings to the CPUC that SCE failed to implement an effective recordkeeping system sufficient to capture all required data for first aid incidents. As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the mechanism and return to ratepayers the $20 million it has already received. SCE has also proposed to withdraw the pending rewards for the 2001 – 2003 time frames. SCE has taken remedial action to address the issues identified, including revising its organizational structure and overall program for environmental, health and safety compliance, disciplining employees who committed wrongdoing and terminating one employee. SCE submitted a report on the results of its investigation to the CPUC on December 3, 2004. System Reliability In light of the problems uncovered with the PBR mechanisms discussed above, SCE conducted an investigation into the third PBR metric, system reliability for the years 1997 – 2003. SCE received $8 million in reliability incentive awards for the period 1997 – 2000 and applied for a reward of $5 million for 2001. For 2002, SCE’s data indicated that it earned no reward and incurred no penalty. For 2003, based on the application of the PBR mechanism, it would incur a penalty of $3 million and accrued a charge for that amount in 2004. On February 28, 2005, SCE provided its final investigation report to the CPUC concluding that the reliability reporting system was working as intended.
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Table of ContentsCPUC Investigation On June 15, 2006, the CPUC instituted a formal investigation to determine whether and in what amounts to order refunds or disallowances of past and potential PBR rewards for customer satisfaction, employee safety and system reliability portions of PBR. In June 2006, the CPSD of the CPUC issued its report regarding SCE’s PBR program, recommending that the CPUC impose various refunds and penalties on SCE. Subsequently, in September 2006, the CPSD and other intervenors, such as the CPUC’s DRA and The Utility Reform Network, filed testimony on these matters recommending various refunds and penalties be imposed on SCE. In their testimony, the various parties made refund and penalty recommendations that range up to the following amounts: refund or forgo $48 million in rewards for customer satisfaction, impose $70 million in penalties for customer satisfaction, refund or forgo $35 million in rewards for employee safety, impose $35 million in penalties for employee safety, impose $102 million in statutory penalties, refund $84 million related to amounts collected in rates for employee bonuses (“results sharing”), refund $4 million of miscellaneous survey expenses, and require $10 million of new employee safety programs. These recommendations total up to $388 million. On October 16, 2006, SCE filed testimony opposing the various refund and penalty recommendations of the CPSD and other intervenors. On October 1, 2007, a POD was released ordering SCE to refund $136 million, before interest, and pay a statutory penalty of $40 million. Included in the amount to be refunded are $28 million related to customer satisfaction rewards, $20 million related to employee safety rewards, and $77 million related to results sharing. The decision requires that the proposed results sharing refund of $77 million (based on year 2000 data) be adjusted for attrition and escalation which increases the results sharing refund to $88 million. Interest as of June 30, 2008, based on amounts collected for customer satisfaction, employee safety incentives and results sharing, including escalation and attrition adjustments, would add an additional $31 million to this amount. The POD also requires SCE to forgo $35 million in rewards for which it would have otherwise been eligible. Included in the amount to be forgone is $20 million related to customer satisfaction rewards and $15 million related to employee safety rewards. On October 31, 2007, SCE appealed the POD to the CPUC. The CPSD and an intervenor also filed appeals. The CPSD appeal requested that: (1) the statutory penalty be increased from $40 million to $83 million (2) a penalty be imposed under the PBR customer satisfaction and employee safety mechanisms in the amount of $48 million and $35 million, respectively, and (3) SCE refund/forgo rewards earned under the customer satisfaction and employee safety mechanisms of $48 million and $35 million, respectively. The appealing intervenor asked that the statutory penalty be increased to as much as $102 million. Oral argument on the appeals took place on January 30, 2008, and it is uncertain when the CPUC will issue a decision. SCE cannot predict the outcome of the appeal. Based on SCE’s proposed refunds, the combined recommendations of the CPSD and other intervenors, as well as the POD, the potential refunds and penalties could range from $52 million up to $388 million. SCE has recorded an accrual at the lower end of this range of potential loss and is accruing interest (approximately $17 million as of June 30, 2008) on collected amounts. The system reliability component of PBR was not addressed in the POD. Pursuant to an earlier order in the case, system reliability incentives will be addressed in a second phase of the proceeding, which commenced with the filing of SCE’s opening testimony in September 2007. In that testimony, SCE confirmed that its PBR system reliability results, which reflected rewards of $13 million for 1997 through 2002 and a penalty of $3 million in 2003 were valid. An indefinite suspension of the schedule for the second phase of the proceeding pending resolution of the appeals of the POD has been granted. SCE cannot predict the outcome of the second phase. EME Homer City New Source Review Notice of Violation On June 12, 2008, EME Homer City received an NOV from the US EPA alleging that, beginning in 1988, EME Homer City (or former owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the Prevention of
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Table of ContentsSignificant Deterioration requirements of the Clean Air Act. The US EPA also alleges that EME Homer City has failed to file timely and complete Title V permits. EME Homer City intends to meet with the US EPA to discuss the alleged violations. EME Homer City is investigating the claims made by the US EPA in the NOV and potential responses and cannot predict at this time what effect this matter may have on its facilities, its results of operations, financial position or cash flows. EME 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 EME Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting the defense of the claims. ISO Disputed Charges On April 20, 2004, the FERC issued an order concerning a dispute between the ISO and the Cities of Anaheim, Azusa, Banning, Colton and Riverside, California over the proper allocation and characterization of certain transmission service related charges. The order reversed an arbitrator’s award that had affirmed the ISO’s characterization in May 2000 of the charges as Intra-Zonal Congestion costs and allocation of those charges to scheduling coordinators in the affected zone within the ISO transmission grid. The April 20, 2004 order directed the ISO to shift the costs from scheduling coordinators in the affected zone to the responsible participating transmission owner, SCE. The potential cost to SCE, net of amounts SCE expects to receive through the PX, SCE’s scheduling coordinator at the time, is estimated to be approximately $20 million to $25 million, including interest. On April 20, 2005, the FERC stayed its April 20, 2004 order during the pendency of SCE’s appeal filed with the Court of Appeals for the D.C. Circuit. On March 7, 2006, the Court of Appeals remanded the case back to the FERC at the FERC’s request and with SCE’s consent. On March 29, 2007, the FERC issued an order agreeing with SCE’s position that the charges incurred by the ISO were related to voltage support and should be allocated to the scheduling coordinators, rather than to SCE as a transmission owner. The Cities filed a request for rehearing of the FERC’s order on April 27, 2007. On May 25, 2007, the FERC issued a procedural order granting the rehearing application for the limited purpose of allowing the FERC to give it further consideration. In a future order, FERC may deny the rehearing request or grant the requested relief in whole or in part. SCE believes that the most recent substantive FERC order correctly allocates responsibility for these ISO charges. However, SCE cannot predict the final outcome of the rehearing. If a subsequent regulatory decision changes the allocation of responsibility for these charges, and SCE is required to pay these charges as a transmission owner, SCE may seek recovery in its reliability service rates. SCE cannot predict whether recovery of these charges in its reliability service rates would be permitted. Leveraged Lease Investments At June 30, 2008, Edison Capital had a net leveraged lease investment, before deferred taxes, of $53 million in three aircraft leased to American Airlines. American Airlines reported net losses for its first and second quarters in 2008 and previously reported losses for a number of years prior to 2006. A default in the leveraged lease by American Airlines could result in a loss of some or all of Edison Capital’s lease investment. At June 30, 2008, American Airlines was current in its lease payments to Edison Capital. Midway-Sunset Cogeneration Company San Joaquin Energy Company, a wholly owned subsidiary of EME, owns a 50% general partnership interest in Midway-Sunset, which owns a 225 MW cogeneration facility near Fellows, California. Midway-Sunset is a party to several proceedings pending at the FERC because Midway-Sunset was a seller in the PX market during 2000 and 2001, both for its own account and on behalf of SCE and PG&E, the utilities to which the majority of Midway-Sunset’s power was contracted for sale. As a seller into the PX market, Midway-Sunset is potentially liable for refunds to purchasers in these markets. On December 20, 2007, Midway-Sunset entered into a settlement agreement in the amount of $86 million (including interest) with SCE, PG&E, SDG&E and certain California state parties to resolve Midway-Sunset’s
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Table of Contentsliability in the FERC refund proceedings. Midway-Sunset concurrently entered into a separate agreement with SCE and PG&E that provides for pro-rata reimbursement to Midway-Sunset by the two utilities of the portions of the agreed to refunds that are attributable to sales made by Midway-Sunset for the benefit of the utilities (Midway-Sunset did not retain any proceeds from power sold into the PX market on behalf of SCE and PG&E in excess of the amounts to which it was entitled under the pre-existing power sales contracts, but instead passed through those proceeds to the utilities). The settlement, which had been approved previously by the CPUC, was approved by the FERC on April 2, 2008. During the period in which Midway-Sunset’s generation was sold into the PX market, amounts SCE received from Midway-Sunset for its pro-rata share of such sales were credited to SCE’s customers against power purchase expenses through the ratemaking mechanism in place at that time. During the second quarter of 2008, SCE reimbursed Midway-Sunset for its pro-rata share of the Midway-Sunset liability in the amount of approximately $43 million. In addition, SCE, as party to the Midway-Sunset settlement agreement, received a $20 million generator refund. The amount reimbursed to and received from Midway-Sunset (net amount of $23 million) were charged/refunded to ratepayers through regulatory mechanisms. SCE’s reimbursement to Midway-Sunset and the refund payment received from Midway-Sunset did not impact earnings. Midwest Generation New Source Review Notice of Violation On August 3, 2007, Midwest Generation received an NOV from the US EPA alleging that, beginning in the early 1990s and into 2003, Midwest Generation or Commonwealth Edison performed repair or replacement projects at six Illinois coal-fired electric generating stations in violation of the Prevention of Significant Deterioration requirements and of the New Source Performance Standards of the Clean Air Act, including alleged requirements to obtain a construction permit and to install best available control technology at the time of the projects. The US EPA also alleges that Midwest Generation and Commonwealth Edison violated certain operating permit requirements under Title V of the Clean Air Act. Finally, the US EPA alleges violations of certain opacity and particulate matter standards at the Illinois Plants. The NOV does not specify the penalties or other relief that the US EPA seeks for the alleged violations. Midwest Generation, Commonwealth Edison, the US EPA, and the United States DOJ are in talks designed to explore the possibility of a settlement. If the settlement talks fail and the DOJ files suit, litigation could take many years to resolve the issues alleged in the NOV. As a result, Midwest Generation is investigating the claims made by the US EPA in the NOV and has identified several defenses which it will raise if the government files suit. Midwest Generation cannot predict the outcome of this matter or estimate the impact on its facilities, its results of operations, financial position or cash flows. On August 13, 2007, Midwest Generation and Commonwealth Edison received a letter signed by several Chicago-based environmental action groups stating that, in light of the NOV, the groups are examining the possibility of filing a citizen suit against Midwest Generation and Commonwealth Edison based presumably on the same or similar theories advanced by the US EPA in the NOV. By letter dated August 8, 2007, Commonwealth Edison 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 NOV. By letter dated August 16, 2007, Commonwealth Edison tendered a request for indemnification to EME for all liabilities, costs, and expenses that Commonwealth Edison may be required to bear if the environmental groups were to file suit. Midwest Generation and Commonwealth Edison are cooperating with one another in responding to the NOV. Navajo Nation Litigation The Navajo Nation filed a complaint in June 1999 in the D.C. District Court against SCE, among other defendants, arising out of the coal supply agreement for Mohave. The complaint asserts claims for, among other things, violations of the federal RICO statute, interference with fiduciary duties and contractual relations, fraudulent misrepresentations by nondisclosure, and various contract-related claims. The complaint claims that
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Table of Contentsthe 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, trebling of that amount, and punitive damages of not less than $1 billion. In March 2001, the Hopi Tribe was permitted to intervene as an additional plaintiff but has not yet identified a specific amount of damages claimed. In April 2004, the D.C. District Court denied SCE’s motion for summary judgment and concluded that a 2003 U.S. Supreme Court decision in an on-going related lawsuit by the Navajo Nation against the U.S. Government did not preclude the Navajo Nation from pursuing its RICO and intentional tort claims. In September 2007, the Federal Circuit reversed a lower court decision on remand in the related lawsuit, finding that the U.S. Government had breached its trust obligation in connection with the setting of the royalty rate for the coal supplied to Mohave. Subsequently, the Federal Circuit denied the U.S. Government’s petition for rehearing. On May 13, 2008, the U.S. Government filed a petition seeking review by the U.S. Supreme Court of the Federal Circuit’s September 2007 decision. The Navajo Nation’s response to the petition was due on August 4, 2008. Pursuant to a joint request of the parties, the D.C. District Court granted a stay of the action in October 2004 to allow the parties to attempt to negotiate a resolution of the issues associated with Mohave with the assistance of a facilitator. In a joint status report filed on November 9, 2007, the parties informed the court that their mediation efforts had terminated and subsequently filed a joint motion to lift the stay. The parties have also filed recommendations for a scheduling order to govern the anticipated resumption of litigation. The Court granted the motion to lift the stay on March 6, 2008, reinstating the case to the active calendar, but has deferred setting an overall schedule for the action pending a determination of disputes concerning the discoverability of certain Navajo documents. SCE cannot predict the outcome of the Navajo Nation’s and Hopi Tribe’s complaints against SCE or the ultimate impact on these complaints of the Supreme Court’s 2003 decision and the on-going litigation by the Navajo Nation against the U.S. Government in the related case. Nuclear Insurance Federal law limits public liability claims from a nuclear incident to the amount of available financial protection, which is currently approximately $10.8 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($300 million). The balance is covered by the industry’s retrospective rating plan that uses deferred premium charges to every reactor licensee 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. Federal regulations require this secondary level of financial protection. The NRC exempted San Onofre Unit 1 from this secondary level, effective June 1994. The current maximum deferred premium for each nuclear incident is approximately $101 million per reactor, but not more than $15 million per reactor may be charged in any one year for each incident. The maximum deferred premium per reactor and the yearly assessment per reactor for each nuclear incident will be adjusted for inflation at least once every five years beginning August 20, 2003. The next inflation adjustment should occur no later than August 20, 2008. Based on its ownership interests, SCE could be required to pay a maximum of approximately $201 million per nuclear incident. However, it would have to pay no more than approximately $30 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. 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 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 utilities with nuclear facilities issues these policies. If losses at any nuclear facility covered by the
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Table of Contentsarrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to approximately $45 million per year. Insurance premiums are charged to operating expense. Palo Verde Nuclear Generating Station Outage and Inspection The NRC held three special inspections of Palo Verde, between March 2005 and February 2007. The combination of the results of the first and third special inspections caused the NRC to undertake an additional oversight inspection of Palo Verde. This additional inspection, known as a supplemental inspection, was completed in December 2007. In addition, Palo Verde was required to take additional corrective actions based on the outcome of completed surveys of its plant personnel and self-assessments of its programs and procedures. The NRC and APS defined and agreed to inspection and survey corrective actions that the NRC embodied in a Confirmatory Action Letter, which was issued in February 2008. APS is presently on track to complete the corrective actions required to close the Confirmatory Action Letter by mid-2009. Palo Verde operation and maintenance costs (including overhead) increased in 2007 by approximately $7 million from 2006. SCE estimates that operation and maintenance costs will increase by approximately $23 million (in 2007 dollars) over the two year period 2008 – 2009, from 2007 recorded costs including overhead costs. SCE is unable to estimate how long SCE will continue to incur these costs. Procurement of Renewable Resources California law requires SCE to increase its procurement of renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than December 31, 2010. SCE filed its compliance report in March 2008. Through the use of flexible compliance rules, SCE demonstrated full compliance for the procurement year 2007 and forecasted full compliance for the procurement years 2008 to 2010. It is unlikely that SCE will have 20% of its annual electricity sales procured from renewable resources by 2010. However, SCE may still meet the 20% target by utilizing the flexible compliance rules. SCE continues to engage in several renewable procurement activities including formal solicitations approved by the CPUC, bilateral negotiations with individual projects and other initiatives. Under current CPUC decisions, potential penalties for SCE’s failure to achieve its renewable procurement objectives for any year will be considered by the CPUC in the context of the CPUC’s review of SCE’s annual compliance filing. Under the CPUC’s current rules, the maximum penalty for failing to achieve renewable procurement targets is $25 million per year. SCE cannot predict whether it will be assessed penalties. RPM Buyers’ Complaint On May 30, 2008, a group of entities referring to themselves as the “RPM Buyers” filed a complaint at the FERC asking that PJM’s RPM, as implemented through the transitional base residual auctions establishing capacity payments for the period from June 1, 2008 through May 31, 2011, be found to have produced unjust and unreasonable capacity prices. The RPM Buyers alleged that the absence of price discipline provided by new capacity resources, together with the ability of existing resources to withhold some capacity within the RPM rules, produced capacity prices in the transition period that are not comparable to those that would have been produced in a competitive market or determined under cost-based regulation, and have requested that the FERC order refunds based on that difference. On July 10, 2008, EME responded to the RPM Buyers’ complaint asking that the same be dismissed based upon various legal precedents. In particular EME argued that the complaint represents little more than a collateral attack on the FERC’s orders approving the RPM settlement and rules and that all of the major factors the RPM Buyers alleged produced unjust and unreasonable prices in the base residual auctions were previously litigated
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Table of Contentsand adjudicated in the contested proceedings involving the RPM settlement. A number of other parties, including PJM, also responded to the RPM Buyers’ complaint asking that the same be dismissed. This matter is currently pending before the FERC. EME cannot predict the outcome of this matter. Scheduling Coordinator Tariff Dispute Pursuant to the Amended and Restated Exchange Agreement, SCE serves as a scheduling coordinator for the DWP over the ISO-controlled grid. In late 2003, SCE began charging the DWP under a tariff subject to refund for FERC-authorized scheduling coordinator and line loss charges incurred by SCE on the DWP’s behalf. The scheduling coordinator charges had been billed to the DWP under a FERC tariff that was subject to dispute. The DWP has paid the amounts billed under protest but requested that the FERC declare that SCE was obligated to serve as the DWP’s scheduling coordinator without charge. The FERC accepted SCE’s tariff for filing, but held that the rates charged to the DWP have not been shown to be just and reasonable and thus made them subject to refund and further review by the FERC. In January 2008, an agreement between SCE and the DWP was executed settling the dispute discussed above. The settlement had been previously approved by the FERC in July 2007. The settlement agreement provides that the DWP will be responsible for line losses and SCE would be responsible for the scheduling coordinator charges. During the fourth quarter of 2007, SCE reversed and recognized in earnings (under the caption “Purchased power” in the consolidated statements of income) $30 million of an accrued liability representing line losses previously collected from the DWP that were subject to refund. As of December 31, 2007, SCE had an accrued liability of approximately $22 million (including $3 million of interest) representing the estimated amount SCE will refund for scheduling coordinator charges previously collected from the DWP. SCE made its first refund payment on February 20, 2008 and the second refund payment was made on February 27, 2008. SCE previously received FERC approval to recover the scheduling coordinator charges from all transmission grid customers through SCE’s transmission rates and on December 11, 2007, the FERC accepted SCE’s proposed transmission rates reflecting the forecast levels of costs associated with the settlement. Upon signing of the agreement in January 2008, SCE recorded a regulatory asset and recognized in earnings the amount of scheduling coordinator charges to be collected through rates. SCE filed a refund report with the FERC on March 4, 2008. FERC approved the refund report on July 8, 2008. 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 obligation to begin acceptance of spent nuclear fuel not later than January 31, 1998. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended delays by the DOE have led to the construction of costly alternatives and associated siting and environmental issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to 0.1¢ per-kWh of nuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating agent, 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. The case was stayed through April 7, 2006, when SCE and the DOE filed a Joint Status Report in which SCE sought to lift the stay and the government opposed lifting the stay. On June 5, 2006, the Court of Federal Claims lifted the stay on SCE’s case and established a discovery schedule. In a Joint Status Report filed on July 1, 2008, the parties requested a trial date in mid-November 2008. On August 6, 2008, the Court set a trial date of April 14 – 28, 2009. SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent nuclear fuel is stored in the San Onofre Units 2 and 3 spent fuel pools and the San Onofre independent spent fuel storage installation where all of Unit 1’s spent fuel located at San Onofre and some of Unit 2 and 3’s spent fuel is stored. SCE, as operating agent, plans to transfer fuel from the Unit 2 and 3 spent fuel pools to the independent
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Table of Contentsstorage installation on an as-needed basis to maintain full core off-load capability for Units 2 and 3. There are now sufficient dry casks and modules available at the independent spent fuel storage installation to meet plant requirements through the end of 2008. SCE plans to add storage capacity incrementally to meet the plant requirements until 2022 (the end of the current NRC operating license). In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed an independent spent fuel storage facility. APS, as operating agent, plans to add storage capacity incrementally to maintain full core off-load capability for all three units. Note 6. Accumulated Other Comprehensive Income (Loss) Information Edison International’s accumulated other comprehensive income (loss) consists of:
Unrealized losses on cash flow hedges, net of tax, at June 30, 2008, included unrealized losses on commodity hedges related to Midwest Generation and EME Homer City futures and forward electricity contracts that qualify for hedge accounting. These losses arise because current forecasts of future electricity prices in these markets are greater than the contract prices. As EME’s hedged positions for continuing operations are realized, $257 million, after tax, of the net unrealized losses on cash flow hedges at June 30, 2008 are expected to be reclassified into earnings during the next 12 months. Management expects that reclassification of net unrealized losses will decrease energy revenue 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 cash flow hedge is designated is through December 31, 2011. Under SFAS No. 133, the portion of a cash flow hedge that does not offset the change in value of the transaction being hedged, which is commonly referred to as the ineffective portion, is immediately recognized in earnings. EME recorded net losses of $18 million and $9 million during the second quarters of 2008 and 2007, respectively, and $31 million and $10 million during the six months ended June 30, 2008 and 2007, respectively, representing the amount of cash flow hedges’ ineffectiveness for continuing operations, reflected in nonutility power generation revenues in Edison International’s consolidated income statements.
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Table of ContentsNote 7. Supplemental Cash Flows Information Edison International’s supplemental cash flows information is:
In connection with certain wind projects acquired during the second quarter of 2008 and the first quarter of 2007, the purchase price included payments that were due upon the start and/or completion of construction. Accordingly, EME accrued for estimated payments during the first six months of 2008 and 2007 which were due upon commencement of construction and/or completion of construction scheduled during 2008 through 2009. Note 8. Fair Value Measurements SFAS No. 157 defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (referred to as an “exit price” in SFAS No. 157). SFAS No. 157 clarifies that a fair value measurement for a liability should reflect the entity’s nonperformance risk. The standard establishes a hierarchy for fair value measurements. Financial assets and liabilities carried at fair value on a recurring basis are classified and disclosed in the three categories outlined below:
Edison International’s assets and liabilities carried at fair value primarily consist of derivative positions for both SCE and EME. These positions may include forward sales and purchases of physical power, options and forward price swaps which settle only on a financial basis (including futures contracts). In assessing the fair value of Edison International’s derivative financial instruments, Edison International uses quoted market prices and forward market prices adjusted for credit risk. The fair value of commodity price contracts takes into account quoted market prices, time value of money, volatility of the underlying commodities and other factors. In addition, SCE nuclear decommissioning trust investments include equity securities, U.S. treasury securities and other fixed income securities.
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Table of ContentsLevel 1 includes derivatives that are exchange traded in active markets, as well as SCE’s nuclear decommissioning trust investments in equity and U.S. treasury securities. The fair values for these derivatives and equity securities are determined using quoted exchange transaction market prices. U.S. treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. Level 2 includes traded derivatives using over-the-counter markets and exchange traded derivatives not classified as Level 1. The fair value of these derivatives is determined using forward market prices adjusted for credit risk. The majority of EME’s Level 2 derivatives are entered into for hedging purposes. Level 2 also includes SCE’s nuclear decommissioning trust investments in other fixed income securities. The fair value of these financial instruments is based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences. Level 3 includes the majority of SCE’s derivatives, including over-the-counter options, bilateral contracts, FTRs and CRRs in the California market, capacity and QF contracts. The fair value of these SCE derivatives is determined using uncorroborated broker quotes and models that mainly extrapolate short-term observable inputs. Level 3 also includes derivatives that trade infrequently such as FTRs and over-the-counter derivatives at illiquid locations and long-term power agreements. For illiquid FTRs, Edison International reviews objective criteria related to system congestion on a quarterly basis and other underlying drivers and adjusts fair value when Edison International concludes a change in objective criteria would result in a new valuation that better reflects the fair value. Changes in fair values are based on hypothetical sale of illiquid positions. For illiquid long-term power agreements, fair value is based upon a discounting of future electricity prices derived from a proprietary model using the risk free discount rate for a similar duration contract, adjusted for credit and 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. When appropriate, valuations are adjusted for various factors including liquidity, bid/offer spreads and credit considerations. Such adjustments are generally based on available market evidence. In the absence of such evidence, management’s best estimate is used. The following table sets forth financial assets and liabilities that were accounted for at fair value as of June 30, 2008 by level within the fair value hierarchy.
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Table of ContentsThe following table sets forth a summary of changes in the fair value of Level 3 derivative contracts, net for the three- and six-month periods ended June 30, 2008.
Nuclear Decommissioning Trusts SCE has collected in rates amounts for the future costs of removal of its nuclear assets, and has placed those amounts in independent trusts. 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. Trust investments (at fair value) include:
Note: Maturity dates as of June 30, 2008.
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Table of ContentsTrust fund earnings (based on specific identification) increase the trust fund balance and the ARO regulatory liability. Net earnings were $26 million and $34 million for the three months ended June 30, 2008 and 2007, respectively, and $57 million and $71 million for the six months ended June 30, 2008 and 2007, respectively. Proceeds from sales of securities (which are reinvested) were $668 million and $987 million for the three months ended June 30, 2008 and 2007, respectively, and $1.5 billion and $2.0 billion for the six months ended June 30, 2008 and 2007, respectively. Cumulative unrealized holding gains, net of losses, were $950 million and $1.1 billion at June 30, 2008 and December 31, 2007, respectively. Realized losses for other-than-temporary impairments were $27 million and $15 million for the three months ended June 30, 2008 and 2007, respectively, and $72 million and $23 million for the six months ended June 30, 2008 and 2007, respectively. Approximately 92% of the cumulative trust fund contributions were tax-deductible. Note 9. Regulatory Assets and Liabilities Regulatory assets included in the consolidated balance sheets are:
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Table of ContentsRegulatory liabilities included in the consolidated balance sheets are:
Note 10. Preferred and Preference Stock Not Subject to Mandatory Redemption In January 2008, SCE repurchased 350,000 shares of 4.08% cumulative preferred stock at a price of $19.50 per share. SCE retired this preferred stock in January 2008 and recorded a $2 million gain on the cancellation of reacquired capital stock (reflected in the caption “Common stock” on the consolidated balance sheets). There is no sinking fund requirement for redemptions or repurchases of preferred stock. Note 11. Business Segments Edison International’s reportable business segments include its electric utility operation segment (SCE), a nonutility power generation segment (EME), and a financial services provider segment (Edison Capital). Included in the nonutility power generation segment are the activities of MEHC, the holding company of EME. MEHC’s only substantive activities were its obligations under the senior secured notes which were paid in full on June 25, 2007. MEHC does not have any substantive operations. Edison International evaluates performance of its business segments based on net income. SCE is a rate-regulated electric utility that supplies electric energy to a 50,000 square-mile area of central, coastal and Southern California. SCE also produces electricity. EME is engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from electric power generation facilities. EME also conducts hedging and energy trading activities in power markets open to competition. Edison Capital is a provider of financial services with investments worldwide.
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Table of ContentsSegment information for the three- and six-month periods ended June 30, 2008 and 2007 was:
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Table of ContentsItem 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations INTRODUCTION This MD&A for the three- and six-month periods ended June 30, 2008 discusses material changes in the consolidated financial condition, results of operations and other developments of Edison International since December 31, 2007, and as compared to the three- and six-month periods ended June 30, 2007. This discussion presumes that the reader has read or has access to Edison International’s MD&A for the calendar year 2007 (the year-ended 2007 MD&A), which was included in Edison International’s 2007 annual report to shareholders and incorporated by reference into Edison International’s Annual Report on Form 10-K for the year ended December 31, 2007, filed with the Securities and Exchange Commission. 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, or that otherwise could impact Edison International or its subsidiaries, 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 Edison International’s Annual Report on 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 & Exchange Commission. Edison International is engaged in the business of holding, for investment, the common stock of its subsidiaries. Edison International’s principal operating subsidiaries are SCE, a rate-regulated electric utility, and EMG. EMG is the holding company for its principal wholly owned subsidiaries, EME, which is engaged in the business of developing, acquiring, owning or leasing, operating and selling energy and capacity from independent power production facilities, and Edison Capital, a provider of capital and financial services. In this MD&A, except when stated to the contrary, references to each of Edison International, SCE, EMG, EME or Edison Capital mean each such company with its subsidiaries on a consolidated basis. References to Edison International (parent) or parent company mean Edison International on a stand-alone basis, not consolidated with its subsidiaries. This MD&A is presented in 8 major sections. The company-by-company discussion of SCE, EMG, and Edison International (parent) includes discussions of liquidity, market risk exposures, and other matters (as relevant to each principal business segment). The remaining sections discuss Edison International on a consolidated basis. The consolidated sections should be read in conjunction with the discussion of each company’s section.
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Table of ContentsCURRENT DEVELOPMENTS The following section provides a summary of current developments related to Edison International’s principal business segments. This section is intended to be a summary of those current developments that management believes are of most importance. This section is not intended to be an all-inclusive list of all current developments related to each principal business segment and should be read together with all sections of this MD&A. EDISON INTERNATIONAL: CURRENT DEVELOPMENTS Federal and State Income Taxes Since the late 1990s, the IRS has been challenging tax return positions related to cross-border leveraged lease transactions. During the second quarter of 2008, several court developments addressing income taxation of cross-border leveraged leases occurred. As previously disclosed, Edison Capital had entered into several cross-border leveraged lease transactions: a foreign power plant and an electric locomotive sale/leaseback transaction entered into in 1993 and 1994 (which the IRS refers to as a sale-in/lease-out or “SILO” transaction), foreign power plants and an electric transmission system lease/leaseback transaction entered into in 1997 and 1998 (which the IRS refers to as a lease-in/lease-out or “LILO” transaction), and a lease/service contract transaction entered into in 2000 – 2002 involving a foreign telecommunications system (which the IRS also refers to as a “SILO” transaction). The court developments represent increased uncertainty about the tax treatment of SILOs and LILOs generally. The IRS continues to challenge tax benefits taken by Edison Capital in its 1993 – 1994 and 1997 – 1998 transactions and is expected to challenge Edison Capital’s 2000-2002 transactions. Despite these developments, Edison International believes it properly reported these transactions based on applicable statutes, regulations and case law and, in the absence of any settlement with the IRS, will continue to vigorously defend its tax treatment of these leases. Recent developments, however, underscore the uncertain nature of tax conclusions in this area. Edison International believes that its maximum earnings exposure related to these leases, measured as of June 30, 2008, is approximately $1.25 billion after taxes. The exposure includes recomputing the cumulative earnings under the leases in accordance with lease accounting rules, and recording related interest. This exposure does not include IRS asserted penalties of 20%, as Edison International does not believe that even if the tax benefits taken by Edison Capital are successfully challenged by the IRS that these penalties would be sustained. The current and future income and cash positions of SCE and EME are virtually unaffected by these leases. Edison International will continue to monitor and evaluate its lease transactions with respect to future events. Future adverse developments, including further adverse case law developments, could change Edison International’s current conclusions. As previously disclosed, Edison International has been engaged in settlement negotiations with the IRS. These negotiations seek to resolve the lease issues in their entirety and all other outstanding tax disputes for the years 1994 through 2002, including certain affirmative claims for unrecognized tax benefits. See “Edison International Notes to Consolidated Financial Statements—Note 3. Income Taxes.” These negotiations have progressed to the point where Edison International and the IRS have reached nonbinding, preliminary understandings on the material principles for resolving such tax disputes on a “global” basis, including the lease issues. Final resolution of such disputes, however, is subject to reaching definitive agreements on final terms and calculations, mutually satisfactory documentation, and review of all or a portion of such settlements by the Staff of the Joint Committee on Taxation, a committee of the United States Congress (the “Joint Committee”). Were Edison International and the IRS to implement the preliminary understanding regarding the leases, Edison International anticipates that it will be required to terminate the leases as an interim step in the implementation of
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Table of Contentsthe overall settlement before executing final agreements with the IRS and before review by the Joint Committee. Edison Capital and its subsidiaries have executed term sheets with the counterparties to its SILOs and LILOs which contemplate termination of the leases subject to the parties agreeing to and executing definitive agreements and to a final settlement agreement with the IRS. Upon termination of the leases, the lessees would be required to make termination payments from certain collateral deposits associated with the leases. Termination of the leases, which may occur in 2008, would result in Edison International recording an after-tax charge to earnings currently estimated to be at least $650 million, and potentially up to the maximum earnings exposure indicated above. If all settlements included in the global settlement discussions were ultimately concluded consistent with the preliminary understandings, Edison International would expect that the settlement of the disputed lease issues and the resolution of the above-mentioned affirmative claims would result in a portion of the charge initially recorded upon termination of the leases being offset and/or reduced, and the net after-tax earnings charge that would remain is currently expected to be less than half of the maximum after-tax earnings exposure, calculated as of June 30, 2008, discussed above. Were all settlements completed in a manner consistent with the preliminary understandings, the net cash impact upon Edison International as a whole of the settlements and lease terminations would be positive over time, and it is not anticipated that borrowings would be required in connection with implementation of the settlements. There can be no assurance, however, about the timing of final settlements with the IRS or that such final settlements will be ultimately consummated. Moreover, even if final settlements are reached with the IRS, review by the Joint Committee could result in adjustments. The IRS and Edison International may not reach final agreements that implement the preliminary understandings, or they may reach final agreements but conditions to consummating them may not be satisfied. If Edison International terminated the SILO and LILO leases without consummating the settlements, then it could not seek through litigation with the IRS future deferred tax benefits that may have been otherwise available in the absence of termination. To the extent that an acceptable settlement is not reached with the IRS, Edison International will continue to vigorously defend its tax treatment of the leases and is prepared to take legal action. If Edison International were to commence litigation in certain forums, it would need to make payments of the disputed taxes, along with interest and any penalties asserted by the IRS, and thereafter pursue refunds. In the other litigation forum (the Tax Court), no upfront payment would be required. In 2006, Edison International paid $111 million of the taxes, interest and penalties for tax year 1999 followed by a refund claim for the same amount. The IRS did not act on this refund claim within the statutory six month period, which provides Edison International with the option of being able to take legal action to assert its refund claim. To the extent an acceptable settlement is not reached with the IRS, Edison International would expect to file a refund claim for any taxes and penalties paid for the 1994 – 1996 tax years related to the leases. Edison International has not decided whether and to what extent it would make additional payments related to later tax years to fund its right to litigate in certain forums should the global settlement discussed above not be consummated. See “Federal and State Income Taxes” for further information. Enterprise-Wide Software System Project Progress continued during 2008 for the installation of SAP’s Enterprise Resource Planning system. On July 1, 2008, Edison International implemented SAP’s financial, supply chain, and certain work management modules at SCE. In addition, Edison International also implemented the human resources module at SCE and EMG. Edison International expects to implement additional SAP modules in the future.
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Table of ContentsSCE: CURRENT DEVELOPMENTS 2009 General Rate Case Proceeding On November 19, 2007, SCE filed its GRC application and subsequently revised its requested 2009 base rate revenue requirement to $5.162 billion. After considering the effects of sales growth and other offsets, SCE’s request would be a $695 million increase over current authorized base rate revenue. On April 15, 2008, the DRA submitted testimony recommending that SCE’s 2009 base rate revenue requirement be increased by approximately $19 million, $676 million less than SCE’s revised request, mainly due to: reductions in capital-related costs, operating and maintenance expense, administrative and general expense, and other miscellaneous proposed reductions. Testimony submitted by TURN, another intervenor, seeks to reduce SCE’s 2009 request by an additional $195 million over the DRA proposed adjustments, mainly due to reduced depreciation expense. See “SCE: Regulatory Matters—Current Regulatory Developments—2009 General Rate Case Proceeding” for further discussion. 2009 FERC Rate Case On August 1, 2008, SCE filed a revision to its Transmission Owner Tariff with a requested effective date of October 1, 2008 to reflect a proposed $129 million increase in its retail transmission revenue requirements (or a 39% increase over the current retail transmission revenue requirement). If the FERC approves this requested increase, this would amount to a 1.2% system average rate increase due to an increase in transmission capital-related costs as well as the increases in transmission operating and maintenance expenses that SCE expects to incur in 2009 to maintain grid reliability. The proposed transmission revenue requirement is based on an overall return on equity of 12.7%, which is composed of a 12.0% base ROE and 0.7% in transmission incentives previously approved by the FERC (see “SCE: Regulatory Matters—Current Regulatory Developments—FERC Construction Work in Progress Mechanism” for further information). As discussed in “SCE: Liquidity—Capital Expenditures,” SCE is experiencing significant growth in actual and planned expenditures to replace and expand its transmission infrastructure. Solar Photovoltaic Program On March 27, 2008, SCE filed an application with the CPUC to implement its Solar Photovoltaic (PV) Program to develop up to 250 MW of utility-owned Solar PV generating facilities ranging in size from 1 to 2 MW each. Targeted at commercial and industrial rooftop space in SCE’s service territory, SCE’s program will use rooftop space from entities that would not otherwise be typical candidates for the net energy metering tariff, which allows customers to offset their usage with electricity generated at their own facilities. SCE proposes to develop these projects at a rate of approximately 50 MW per year at an average cost of $3.50/watt. The estimated base case capital cost for the Solar PV Program is $875 million over the period of the program (2008 – 2013). SCE proposes a reasonableness threshold of $963 million. Subject to CPUC approval, the capital expenditures will be eligible to be included in SCE’s earning asset base if the actual costs of the program are equal to or lower than the reasonableness threshold amount. SCE also proposes to apply the CPUC-approved 100 basis point incentive adder for qualifying utility-owned renewable energy investments. SCE also requested to track costs spent on projects prior to the receipt of the CPUC’s final decision in a memorandum account for potential future recovery. SCE expects a decision on the memorandum account in the fourth quarter of 2008. SCE expects to continue to move forward with projects in advance of the final CPUC decision. Several parties have filed protests to SCE’s Solar PV program application. A scoping memorandum was issued on July 27, 2008 which identified issues to be addressed in the proceeding as well as set evidentiary hearings for November 2008 and a final decision for March 2009. SCE cannot predict the final outcome of this proceeding. Impacts on Customer Rates Natural gas prices have significantly increased during 2008 over forecasted prices used to set current generation rate levels and are subject to considerable volatility for the remainder of 2008 and in 2009. The increase in natural gas prices and the effect on power prices have, and are expected to continue to negatively impact SCE’s
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Table of ContentsERRA balancing account, which is expected to result in customer rate increases. For further discussion of the ERRA regulatory matters and the impact on customer rates, see “SCE: Regulatory Matters—Current Regulatory Developments—Impact of Regulatory Matters on Customer Rates” and “SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings.” EMG: CURRENT DEVELOPMENTS Industry Developments Commodity Prices The 24-hour average market prices for energy at the Northern Illinois Hub and PJM West Hub increased 18% and 23%, respectively, during the six months ended June 30, 2008, compared to the corresponding period in 2007. In addition, the forward energy market prices for 2009 for these locations increased 21% and 41%, respectively, at June 30, 2008 from December 31, 2007. At June 30, 2008, EME had entered into hedge contracts that are recorded at fair value in its consolidated financial statements. Since forward energy prices have increased at June 30, 2008, the hedge contracts are reflected as a liability, with the effective portion of the contracts recorded as a reduction of shareholder’s equity ($379 million after tax). Subsequent to June 30, 2008, forward energy market prices decreased (forward market prices for 2009 at July 29, 2008 decreased 18% and 22%, respectively, for the above locations from June 30, 2008) reflecting the volatile nature of commodity prices. See “EMG: Market Risk Exposures—Commodity Price Risk” for further discussion. During the three-month period ended June 30, 2008 of historically high forward energy market prices, EME increased its hedge position by approximately 11.2 million megawatt hours. Regulatory Developments In July 2008, the District of Columbia Circuit Court of Appeals vacated the US EPA’s CAIR and remanded it to the US EPA. In addition, because Pennsylvania and Illinois promulgated their regulations in response to the CAIR, there is substantial uncertainty as to the impact of the Court’s decision on these state regulations. Notwithstanding these developments, the Illinois plants and Homer City facilities continue to be governed by state rules as well as the existing “SIP Call” ozone season NOX cap-and-trade program (which was due to be replaced by the CAIR). For further discussion, see “Other Developments—Environmental Matters—Air Quality Regulation—Clean Air Interstate Rule.” Based on the CAIR requirements, Midwest Generation purchased $48 million of annual NOX allowances under the new CAIR annual NOX program which was vacated by the court ruling discussed above. As a result of this decision, the annual NOX allowances may no longer be required. Midwest Generation is currently evaluating the above decision including whether the purchased annual NOX allowances are impaired which could result in a charge against income during the third quarter ending September 30, 2008. Extension of Production Tax Credits New wind projects currently receive federal subsidies in the form of production tax credits. Production tax credits for a ten-year period are available for new projects placed in service prior to December 31, 2008. There have been proposals to extend the deadline for production tax credits beyond the end of 2008, but such proposals have not been enacted. Although EME believes there is significant support for extending production tax credits, congressional action may be delayed until next year, and there can be no guarantee that it will occur at all. EME supports extension of production tax credits, without an interruption, to encourage construction of renewable energy projects and plans to monitor legislative developments.
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Table of ContentsEME Growth Activities Renewable Energy At June 30, 2008, EME had 695 MW of wind projects in service and another 390 MW of wind projects under construction, with scheduled completion dates during 2008. As of the same date, EME had a development pipeline of potential wind projects with an estimated installed capacity of approximately 5,000 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. This development pipeline is supported by turbine purchase commitments totaling 1,061 MW for new wind projects. The majority of the turbines are scheduled to be delivered before the end of 2010. Key activities during the second quarter of 2008 with respect to wind projects were:
Subsequent to June 30, 2008, EME commenced construction of the 100 MW High Lonesome wind project located in New Mexico and completed construction and commenced operations of the 61 MW Mountain Wind I wind project located in Wyoming. In addition, EME submitted bids in competitive solicitations to supply power from solar projects under development in California and has had a number of its proposals short-listed. Initial site and equipment selection have been completed along with preliminary economic feasibility studies. Further project development activities are underway to obtain transmission interconnection, control of sites, and construction costs estimates, as well as the negotiation of power sales agreements with local utilities. Thermal Energy During the first quarter of 2008, a subsidiary of EME was awarded through a competitive bidding process a ten-year power sales contract with SCE for the output of a 479 MW gas-peaking facility located in the City of Industry, California, which is referred to as the Walnut Creek project. The power sales agreement is subject to approval of the CPUC which SCE requested on April 4, 2008. CPUC approval is expected to be granted by late 2008. As an affiliate transaction, the contract is also subject to FERC approval, which was requested on May 2, 2008. Deliveries under the power sales agreement are expected to commence in 2013. During the second quarter of 2008, EME and its subsidiary entered into an agreement to purchase major equipment for the project.
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Table of ContentsSOUTHERN CALIFORNIA EDISON COMPANY SCE: LIQUIDITY Overview As of June 30, 2008, SCE had cash and equivalents of $185 million ($112 million of which was held by SCE’s consolidated VIEs). As of June 30, 2008, long-term debt, including current maturities of long-term debt, was $5.47 billion. On March 12, 2008, SCE amended its existing $2.5 billion credit facility, extending the maturity to February 2013 while retaining existing borrowing costs as specified in the facility. The amendment also provides four extension options which, if all exercised, will result in a final termination in February 2017. At June 30, 2008, the credit facility supported $197 million in letters of credit and $800 million of short-term debt outstanding, leaving $1.5 billion available for liquidity purposes. SCE’s estimated cash outflows during the 12-month period following June 30, 2008 are expected to consist of:
SCE expects to meet its continuing obligations, including cash outflows for operating expenses and power-procurement, through cash and equivalents on hand, operating cash flows and short-term borrowings. Projected capital expenditures are expected to be financed through operating cash flows and the issuance of short- and long-term debt and preferred equity. On February 13, 2008, President Bush signed the Economic Stimulus Act of 2008 (2008 Stimulus Act). The 2008 Stimulus Act includes a provision that provides accelerated bonus depreciation for certain capital expenditures incurred during 2008. Edison International expects that certain capital expenditures incurred by SCE during 2008 will qualify for this accelerated bonus depreciation, which would provide additional cash flow benefits estimated to be approximately $175 million for 2008. Any cash flow benefits resulting from this accelerated depreciation should be timing in nature and therefore should result in a higher level of accumulated deferred income taxes reflected on SCE’s consolidated balance sheets. Timing benefits related to deferred taxes will be incorporated into future ratemaking proceedings, impacting future period cash flow and rate base. SCE’s liquidity may be affected by, among other things, matters described in “SCE: Regulatory Matters” and “Commitments, Guarantees and Indemnities.” Capital Expenditures As discussed under the heading “SCE: Liquidity—Capital Expenditures” in the year-ended 2007 MD&A, SCE is experiencing significant growth in actual and planned capital expenditures to replace and expand its distribution and transmission infrastructure, and to construct and replace generation assets. SCE’s 2008 through 2012 capital forecast includes total spending of up to $19.9 billion, including capital spending for SCE’s Solar PV Program. Recovery of certain of these expenditures is subject to regulatory approvals. During the three- and six-month periods ended June 30, 2008, SCE spent $608 million and $1.17 billion, respectively, in capital expenditures related to its 2008 capital plan. SCE projected capital expenditures for the next five years are as follows: remainder of 2008 – $1.7 billion, 2009 – $4.1 billion, 2010 – $4.5 billion, 2011 – $4.6 billion and 2012 – $3.8 billion.
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Table of ContentsCredit Ratings At June 30, 2008, SCE’s credit ratings were as follows:
SCE cannot provide assurance that its current credit ratings will remain in effect for any given period of time or that one or more of these ratings will not be changed. These credit ratings are not recommendations to buy, sell or hold its securities and may be revised at any time by a rating agency. Dividend Restrictions and Debt Covenants The CPUC regulates SCE’s capital structure and limits the dividends it may pay Edison International (see “Edison International (Parent): Liquidity” for further discussion). 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 determines compliance with this capital structure based on a 13-month weighted-average calculation. At June 30, 2008, SCE’s 13-month weighted-average common equity component of total capitalization was 50.5% resulting in the capacity to pay $307 million in additional dividends. SCE has a debt covenant in its credit facility that requires a debt to total capitalization ratio of less than or equal to 0.65 to 1 to be met. At June 30, 2008, SCE’s debt to total capitalization ratio was 0.46 to 1. Margin and Collateral Deposits SCE has entered into certain margining agreements for power and gas trading activities in support of its procurement plan as approved by the CPUC. SCE’s margin deposit requirements under these agreements can vary depending upon the level of unsecured credit extended by counterparties and brokers, changes in market prices relative to contractual commitments, and other factors. During the first quarter of 2008, SCE implemented FIN 39-1 and elected the option to net collateral with the fair value of derivative assets/liabilities under master netting arrangements. Amounts recognized for cash collateral received from others that have been offset against net derivative assets totaled $18 million at June 30, 2008. In addition, at June 30, 2008, SCE had deposits of $204 million (consisting of $7 million in cash that was not offset against net derivative positions and was reflected in “Margin and collateral deposits” on the consolidated balance sheets and $197 million in letters of credit) with counterparties and other brokers. Cash deposits with brokers and counterparties earn interest at various rates. Future cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2008, due to changes in wholesale power and natural gas prices. SCE estimates that margin and collateral requirements for energy contracts outstanding as of June 30, 2008, could increase by approximately $555 million over the remaining life of the contracts using a 95% confidence level.
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Table of ContentsThe credit risk exposure from counterparties for power and gas trading activities are measured as the difference between the contract price and current fair value of open positions. 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. At June 30, 2008, the amount of exposure as described above, broken down by the credit ratings of SCE’s counterparties, was as follows:
SCE has tolling contracts in which SCE purchases the output of a plant from the counterparty. SCE’s structured transactions may be for multiple years which increases the volatility of the fair value position of the transaction. A number of the counterparties with which SCE has structured transactions do not currently have an investment grade rating or are below investment grade. SCE seeks to mitigate this risk through diversification of its structured transactions, when available. Despite this, there can be no assurance that these efforts will be successful in mitigating credit risk from contracts. SCE requires that counterparties with below investment grade ratings or those that do not currently have an investment grade rating post collateral. In the event of default by the counterparty, SCE would be able to use that collateral to pay for the commodity purchased or to pay the associated obligation in the event of default by the counterparty. Furthermore, all of the contracts that SCE has entered into with counterparties are entered into under SCE’s short-term and long-term procurement plan which has been approved by the CPUC. As a result, SCE would qualify for regulatory recovery for any defaults by counterparties on these transactions. In addition, SCE closely monitors any changes that may affect the counterparties’ ability to perform. SCE: REGULATORY MATTERS Current Regulatory Developments This section of the MD&A describes significant regulatory issues that may impact SCE’s consolidated financial condition or results of operation. Impact of Regulatory Matters on Customer Rates The following table summarizes SCE’s system average rates and the portion related to CDWR which is not recognized as revenue by SCE, but included in the SCE system average rate, at various dates in 2007 and 2008:
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Table of ContentsThe rate changes in 2008 resulted from the following:
SCE expects to file an ERRA Trigger Application in the third quarter of 2008 due to higher gas and power prices than the forecast prices used to set current generation rate levels and expects to increase customer rates before year-end 2008. 2009 General Rate Case Proceeding As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—2009 General Rate Case Proceeding” in the year-ended 2007 MD&A, SCE filed its GRC application on November 19, 2007. The application requested a 2009 base rate revenue requirement of $5.199 billion. Hearings were completed in June 2008 and briefing is expected to be completed on August 8, 2008. At the end of the hearings, SCE agreed to several adjustments to its request and revised its forecasts to reflect lower customer growth and meter connections due to the economic downturn in southern California. SCE’s revised request for 2009 is $5.162 billion. After considering the effects of sales growth and other offsets, SCE’s revised request would be a $695 million increase over current authorized base rate revenue. If the CPUC approves these requested increases and allocates them to ratepayer groups on a system average percentage change basis, the percentage increases over current base rates and total rates are estimated to be 15.57% and 5.96%, respectively. The revised request would result in 2010 and 2011 base rate revenue requirement increases, net of sales growth, of $197 million and $257 million, respectively. As a result of SCE’s revised request, the DRA’s recommended increase of approximately $19 million, which was submitted on April 15, 2008, now represents a difference of $676 million from SCE’s revised base rate revenue. The $676 million difference is mainly due to reductions proposed by DRA including: a reduction in capital-related costs of approximately $186 million, which includes recommended changes in methods for calculating depreciation expense; a reduction in operating and maintenance expense of approximately $286 million; a reduction in administrative and general expense of approximately $192 million mainly related to a reduction in pension and benefits, the elimination of results sharing as well as a reduction in long-term incentives and other executive compensation; and other miscellaneous proposed reductions. Additionally, as a result of SCE’s revised request, TURN’s recommendation now seeks to reduce SCE’s revised 2009 request by an additional $195 million over the DRA adjustments, primarily due to a further reduction in depreciation expenses. SCE cannot predict the revenue requirement the CPUC will ultimately authorize or precisely when a final decision will be adopted although a final decision is expected prior to year-end. 2008 Cost of Capital Proceeding On December 21, 2007, the CPUC granted SCE’s requested rate-making capital structure of 43% long-term debt, 9% preferred equity and 48% common equity for 2008. The CPUC also authorized SCE’s 2008 cost of long-term debt of 6.22%, cost of preferred equity of 6.01% and a return on common equity of 11.5%. The impact of this Phase I decision resulted in a $7 million decrease in SCE’s 2008 annual revenue requirement. On May 29, 2008, the CPUC issued a final decision on Phase II of the proceeding, replacing the former annual cost of capital application with a multi-year mechanism, which would not require a new cost of capital application to be filed until April 2010. The decision also adopted a trigger mechanism which provides for an automatic adjustment to return on equity and embedded costs of long-term debt and preferred stock during the intervening years between the cost of capital filings if certain thresholds are reached.
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Table of ContentsEnergy Efficiency Shareholder Risk/Reward Incentive Mechanism As discussed under the heading “SCE: Regulatory Matters—Energy Efficiency Shareholder Risk/Reward Incentive Mechanism” in the year-ended 2007 MD&A, the CPUC issued a decision in September 2007 that adopted an Energy Efficiency Risk/Reward Incentive mechanism. The mechanism allows for both incentives and economic penalties based on SCE’s performance toward meeting CPUC goals for energy efficiency. Under this mechanism, SCE is scheduled to file an advice letter in September 2008 requesting recovery of the earnings claim for the 2006 and 2007 timeframe, however, the timing of claims is linked to the completion of CPUC reports. The first progress payment, for SCE’s 2006-2007 energy efficiency portfolio performance, will be based on a CPUC report scheduled to be complete in August 2008. SCE currently projects, based on preliminary results and through the advice letter process (see below for discussion of an alternative dispute resolution process), that it will record a progress payment in the range of $41 million to $49 million in the fourth quarter of 2008 for the first two years (2006 – 2007) of the program cycle. Delays in the CPUC report expected in August 2008 could cause a delay in recognizing earnings for the progress payment. On July 3, 2008, the Natural Resources Defense Council filed a request with the CPUC for an alternative dispute resolution process to address the first interim earnings claim for the 2006-2008 energy efficiency program cycle. The alternative dispute resolution process may be requested by a party at any time and is a voluntary process which may be utilized by parties to ensure a timely solution to cases. The alternative dispute resolution process could modify or negate the use of the advice letter process, including the results of the CPUC report expected in August 2008. Depending on the outcome of the alternative dispute resolution process, the parties may revert to the advice letter process. Under the alternative dispute resolution process, the progress payment amount, as well as timing of recognition, may differ from SCE’s current projection. FERC Construction Work in Progress Mechanism As discussed under the headings “SCE: Regulatory Matters—Current Regulatory Developments—FERC Transmission Incentives” and “—FERC Construction Work in Progress Mechanism” in the year-ended 2007 MD&A, on December 21, 2007, SCE filed a revision to its Transmission Owner Tariff to collect 100% of CWIP in rate base for its Tehachapi, DPV2, and Rancho Vista projects. In the CWIP filing, SCE proposed a single-issue rate adjustment ($45 million or a 14.4% increase) to SCE’s currently authorized base transmission revenue requirement to be made effective on March 1, 2008 and later adjusted for amounts actually spent in 2008 through a new balancing account mechanism. The rate adjustment represents actual expenditures from September 1, 2005 through November 30, 2007, projected expenditures from December 1, 2007 through December 31, 2008, and a ROE (which includes the ROE adders approved for Tehachapi, DPV2 and Rancho Vista). SCE projects that it will spend a total of approximately $244 million, $27 million, and $181 million for Tehachapi, DPV2, and Rancho Vista, respectively, from September 1, 2005 through the end of 2008. The 2008 DPV2 expenditure forecast is limited to projected consulting and legal costs associated with SCE’s continued efforts to obtain regulatory approvals necessary to construct the DPV2 Project. On February 29, 2008, the CWIP filing was approved and SCE implemented the CWIP rate on March 1, 2008, subject to refund on the limited issue of whether SCE’s proposed ROEs are reasonable. On March 28, 2008, the CPUC filed a Petition for Rehearing with the FERC on the FERC’s acceptance of SCE’s proposed ROE for CWIP. Briefs addressing the appropriate ROE were filed by SCE and intervenors in May 2008. In addition, in the order, SCE was directed by FERC to make a compliance filing to provide greater detail on the costs reflected in CWIP rates for 2008. SCE made the compliance filing on March 31, 2008. On April 21, 2008, the CPUC filed a protest of the compliance filing at FERC and requested an evidentiary hearing to be set to further review the costs. SCE filed a response to the CPUC’s protest on May 6, 2008 arguing that the FERC should deny the CPUC’s request for a further hearing. SCE cannot predict the outcome of the matters in this proceeding.
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Table of ContentsEnergy Resource Recovery Account Proceedings As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—Energy Resource Recovery Account Proceedings” in the year-ended 2007 MD&A, the ERRA is the balancing account mechanism to track and recover SCE’s fuel and procurement-related costs. At June 30, 2008, the ERRA was undercollected by $95 million, which was 1.8% of SCE’s prior year’s generation revenue. Based on a forecast of procurement costs, SCE’s ERRA balancing account is estimated to be undercollected by more than 5% by the end of August 2008, and 14.5% by the end of December 2008. This significant undercollection is due to higher gas and power prices than the forecast prices used to set current generation rate levels. SCE expects to file an ERRA Trigger Application in the third quarter of 2008 and expects to increase customer rates before year-end 2008. Peaker Plant Generation Projects As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—Peaker Plant Generation Projects” in the year-ended 2007 MD&A, in response to a CPUC order, SCE constructed four of the five combustion turbine peaker plants, four of which were placed online in August 2007 to help meet peak customer demands and other system requirements. SCE anticipates submitting updated testimony in connection with its December 2007 cost recovery application to revise the total recorded costs as of mid-2008, for the first four peaker plants, to approximately $261 million with additional projected costs for those peaker plants of approximately $2 million. In its cost recovery application, SCE proposed to continue tracking the capital costs of the fifth peaker plant according to the interim cost tracking mechanism that was previously approved by the CPUC for all five peaker projects while they were in construction. Additionally, SCE proposed to file a separate cost recovery application for the fifth peaker after it is installed or its final disposition is otherwise determined (see below for further discussion on the status of the fifth peaker plant). As of June 30, 2008, SCE has incurred capital costs of approximately $38 million for the fifth peaker. Several parties have filed protests or other filings in response to SCE’s cost recovery application. SCE expects to fully recover its costs from these projects, but cannot predict the outcome of regulatory proceedings. SCE expects a CPUC decision on its cost recovery application in late 2008. SCE has continued to pursue the construction of the fifth peaker plant. The required development permit was denied by the City of Oxnard in July 2007 and SCE appealed the denial to the California Coastal Commission. The Commission heard SCE’s appeal on August 6, 2008, but did not reach a final decision and continued the matter until at least October 2008. Procurement of Renewable Resources As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—Procurement of Renewable Resources” in the year-ended 2007 MD&A, California law requires SCE to increase its procurement of renewable resources by at least 1% of its annual retail electricity sales per year so that 20% of its annual electricity sales are procured from renewable resources by no later than December 31, 2010. SCE filed its compliance report in March 2008. Through the use of flexible compliance rules, SCE demonstrated full compliance for the procurement year 2007 and forecasted full compliance for the procurement years 2008 to 2010. It is unlikely that SCE will have 20% of its annual electricity sales procured from renewable resources by 2010. However, SCE may still meet the 20% target by utilizing the flexible compliance rules. SCE continues to engage in several renewable procurement activities including formal solicitations approved by the CPUC, bilateral negotiations with individual projects and other initiatives. Under current CPUC decisions, potential penalties for SCE’s failure to achieve its renewable procurement objectives for any year will be considered by the CPUC in the context of the CPUC’s review of SCE’s annual compliance filing. Under the CPUC’s current rules, the maximum penalty for failing to achieve renewable procurement targets is $25 million per year. SCE cannot predict whether it will be assessed penalties.
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Table of ContentsCalifornia Proposition 7- Solar and Clean Energy Initiative A renewable initiative has qualified for the November 4, 2008 California ballot that would impose a 50% Renewable Portfolio Standard (RPS) on all electric utilities in the state, including investor-owned and municipally-owned utilities. The measure would set an RPS of 20% by 2010, 40% by 2020, and 50% by 2025. It would also reduce, but uncap, penalties for not meeting the annual RPS requirement. Additionally, it would set the minimum price of renewable energy at market price and authorize purchases up to 10% above market price. The measure would also require utilities to sign 20-year bilateral agreements for offers meeting that threshold. Finally, it would shift jurisdiction for setting a market price and permitting transmission from the CPUC to the CEC. The measure is opposed by a coalition of environmentalists, renewable power developers, labor, taxpayer groups, and utilities, and has not received any significant endorsements among these sectors. It is also opposed by both political parties. While the fiscal impacts of the initiative are unknown at this time, SCE is evaluating them and is actively participating in the campaign against the measure. FERC Refund Proceedings As discussed under the heading “SCE: Regulatory Matters—Current Regulatory Developments—FERC Refund Proceedings” in the year-ended 2007 MD&A, SCE is participating in several related proceedings seeking recovery of refunds from sellers of electricity and natural gas who manipulated the electric and natural gas markets during the energy crisis in California in 2000 – 2001 or who benefited from the manipulation by receiving inflated market prices. SCE is required to refund to customers 90% of certain refunds realized by SCE, net of litigation costs, and 10% will be retained by SCE as a shareholder incentive. In November 2005, SCE and other parties entered into a settlement agreement with Enron Corporation and a number of its affiliates, most of which are debtors in Chapter 11 bankruptcy proceedings pending in New York. In the second quarter of 2008, SCE received distributions of approximately $25 million on its allowed bankruptcy claim. Additional distributions are expected but SCE cannot currently predict the amount or timing of such distributions. In May 2008, SCE and a number of other parties entered into a settlement of the FERC refund proceeding issues with NEGT Energy Trading-Power, L.P. (NEGT) and a related party, both of which are debtors in a Chapter 11 proceeding pending in the Maryland bankruptcy court. Under the terms of the settlement, NEGT will provide refunds valued at $66 million, a portion of which will be paid in the form of an allowed, unsecured claim in the Chapter 11 bankruptcy proceeding. SCE’s share of this amount is expected to be approximately $19 million. NEGT will also assign to SCE and the other parties to the settlement a corporate guarantee and surety bond that, subject to collection, will provide an additional $14 million. SCE’s share of the $14 million is yet to be determined. The settlement was approved by the Maryland bankruptcy court on July 24, 2008 but remains subject to approval by the FERC. Market Redesign Technology Upgrade As discussed under the heading “SCE: Regulatory Matters—Market Redesign Technology Upgrade” in the year ended 2007 MD&A, in early 2006, the ISO began a program to redesign and upgrade the wholesale energy market across ISO’s controlled grid, known as the MRTU. The programs under the MRTU initiative are designed to implement market improvements to assure grid reliability, more efficient and cost-effective use of resources, and to create technology upgrades that would strengthen the entire ISO computer system. The MRTU was scheduled for implementation in the fall of 2008, however, the ISO recently announced a further delay beyond 2008. Discussions will be held in September 2008 to determine the timing of the MRTU implementation.
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Table of ContentsSCE: OTHER DEVELOPMENTS Palo Verde Nuclear Generating Station Outage and Inspection As discussed under the heading “SCE: Other Developments—Palo Verde Nuclear Generating Station Inspection” in the year-ended 2007 MD&A, the NRC held three special inspections of Palo Verde, between March 2005 and February 2007. The combination of the results of the first and third special inspections caused the NRC to undertake an additional oversight inspection of Palo Verde. This additional inspection, known as a supplemental inspection, was completed in December 2007. In addition, Palo Verde was required to take additional corrective actions based on the outcome of completed surveys of its plant personnel and self-assessments of its programs and procedures. The NRC and APS defined and agreed to inspection and survey corrective actions that the NRC embodied in a Confirmatory Action Letter, which was issued in February 2008. APS is presently on track to complete the corrective actions required to close the Confirmatory Action Letter by mid-2009. Palo Verde operation and maintenance costs (including overhead) increased in 2007 by approximately $7 million from 2006. SCE estimates that operation and maintenance costs will increase by approximately $23 million (in 2007 dollars) over the two year period 2008 – 2009, from 2007 recorded costs including overhead costs. SCE is unable to estimate how long SCE will continue to incur these costs. SCE: MARKET RISK EXPOSURES SCE’s primary market risks include fluctuations in interest rates, commodity prices and volumes, and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in commodity prices and volumes and counterparty credit losses may temporarily affect cash flows, but are not expected to affect earnings due to expected recovery through regulatory mechanisms. SCE uses derivative financial instruments, as appropriate, to manage its market risks. Interest Rate Risk SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used for liquidity purposes, to fund business operations and to finance capital expenditures. In July 2007, SCE entered into interest rate-locks to mitigate interest rate risk associated with future financings. Due to declining interest rates in late 2007, at December 31, 2007, these interest rate locks had unrealized losses of $33 million. In January and February 2008, SCE settled these interest rate-locks resulting in realized losses of $33 million. A related regulatory asset was recorded in this amount and SCE expects to amortize and recover this amount as interest expense associated with its 2008 financings. Commodity Price Risk As discussed in the year-ended 2007 MD&A, SCE is exposed to commodity price risk associated with its purchases for additional capacity and ancillary services to meet its peak energy requirements as well as exposure to natural gas prices associated with power purchased from QFs, fuel tolling arrangements, and its own gas-fired generation, including SCE’s Mountainview plant. SCE has an active hedging program in place to minimize ratepayer exposure to spot-market price spikes; however, to the extent that SCE does not mitigate the exposure to commodity price risk, the unhedged portion is subject to the risks and benefits of spot-market price movements, which are ultimately passed-through to ratepayers. To mitigate SCE’s exposure to spot-market prices, SCE enters into energy options, tolling arrangements, forward physical contracts, and congestion rights (FTRs and CRRs). SCE also enters into contracts for power and gas options, as well as swaps and futures, in order to mitigate its exposure to increases in natural gas and electricity
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Table of Contentspricing. These transactions are pre-approved by the CPUC or executed in compliance with CPUC-approved procurement plans. In September 2007, the ISO allocated CRRs for the period March 2008 through December 2017 to SCE which will entitle SCE to receive (or pay) the value of transmission congestion between specific locations. These rights will act as an economic hedge against transmission congestion costs in the MRTU environment which was expected to be operational March 31, 2008, but was delayed. The CRRs meet the definition of a derivative under SFAS No. 133. In accordance with SFAS No. 157, SCE recognized the CRRs at a zero fair value due to liquidity reserves. Liquidity reserves against CRRs fair values were provided since there were no quoted long-term market prices for the CRRs allocated to SCE. Although an auction was held in December 2007, the auction results did not provide sufficient evidence of long-term market prices. During the first quarter of 2008, the ISO held an auction for FTRs. SCE participated in the ISO auction and paid $62 million to secure FTRs for the period April 2008 through March 2009. The FTRs will be replaced with CRRs in the MRTU environment. SCE recognized the FTRs at fair value. SCE anticipates amounts paid for FTRs that will no longer be valid in the MRTU environment will be refunded to SCE and has recognized this amount as a receivable from the ISO. Any future fair value changes, given a MRTU market, will be recorded in purchased-power expense and offset through the provision for regulatory adjustments clauses as the CPUC allows these costs to be recovered from or refunded to customers through a regulatory balancing account mechanism. As a result, fair value changes are not expected to affect earnings. SCE records its derivative instruments on its consolidated balance sheets at fair value unless they meet the definition of a normal purchase or sale. Certain derivative instruments do not meet the normal purchases and sales exception because demand variations and CPUC mandated resource adequacy requirements may result in physical delivery of excess energy that may not be in quantities that are expected to be used over a reasonable period in the normal course of business and may then be resold into the market. In addition, certain contracts do not meet the definition of clearly and closely related under SFAS No. 133 since pricing for certain renewable contracts is based on an unrelated commodity. The derivative instrument fair values are marked to market at each reporting period. Any fair value changes for recorded derivatives are recorded in purchased-power expense and offset through the provision for regulatory adjustment clauses – net; therefore, fair value changes do not affect earnings. Hedge accounting is not used for these transactions due to this regulatory accounting treatment. The following table summarizes the fair values of outstanding derivative financial instruments used at SCE to mitigate its exposure to spot market prices:
Quoted market prices, if available, are used for determining the fair value of contracts, as discussed above. If quoted market prices are not available, internally maintained standardized or industry accepted models are used to determine the fair value. The models are updated with spot prices, forward prices, volatilities and interest rates from regularly published and widely distributed independent sources. SCE implemented SFAS No. 157 during the first quarter of 2008. Under SFAS No. 157, when actual market prices, or relevant observable inputs are not
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Table of Contentsavailable it is appropriate to use unobservable inputs which reflect management assumptions, including extrapolating limited short-term observable data and developing correlations between liquid and non-liquid trading hubs. The derivative assets and liabilities whose fair value is based on unobservable inputs are classified as level 3 measurements under SFAS No. 157. The amount of SCE’s level 3 derivative assets and liabilities measured using significant unobservable inputs as a percentage of the total derivative assets and total derivative liabilities measured at fair value was 53% and 100%, respectively. During the first six months of 2008, the level 3 fair values increased as a result of changes in realized and unrealized gains. SCE recorded net realized and unrealized gains of $361 million for the three months ended June 30, 2008 and net realized and unrealized losses of $63 million for the three months ended June 30, 2007. SCE recorded net realized and unrealized gains of $512 million and $42 million for the six months ended June 30, 2008 and 2007, respectively. The changes in net realized and unrealized gains on economic hedging activities were primarily due to increases in forward natural gas prices in 2008, compared to the same period in 2007. Due to expected recovery through regulatory mechanisms unrealized gains and losses may temporarily affect cash flows, but are not expected to affect earnings.
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Table of ContentsEMG: LIQUIDITY Liquidity At June 30, 2008, EMG and its subsidiaries had cash and cash equivalents and short-term investments of $805 million, EMG had a total of $968 million of available borrowing capacity under its credit facilities. EMG’s consolidated debt at June 30, 2008 was $4.0 billion. In addition, EME’s subsidiaries had $3.7 billion of long-term lease obligations related to the sale-leaseback transactions that are due over periods ranging up to 27 years. Capital Expenditures At June 30, 2008, the estimated capital expenditures through 2010 by EME’s subsidiaries related to existing projects, corporate activities and turbine commitments were as follows:
Expenditures for Existing Projects Plant capital expenditures relate to non-environmental projects such as upgrades to boiler and turbine controls, railroad interconnection, replacement of major boiler components, mill inerting projects and ash site disposal development. Environmental expenditures relate to environmental projects such as mercury emission monitoring and control and a selenium removal system at the Homer City facilities and various projects at the Illinois plants to achieve specified emissions reductions such as installation of mercury controls. EME plans to fund these expenditures with debt financings, cash on hand or cash generated from operations. For further discussion regarding these and possible additional capital expenditures, including environmental control equipment at the Homer City facilities, refer to “Edison International: Management’s Overview,” and “Other Developments—Environmental Matters—Air Quality Regulation—Clean Air Interstate Rule—Illinois,” and “Other Developments—Environmental Matters—Air Quality Regulation—Mercury Regulation” in the year ended December 31, 2007 MD&A. Expenditures for New Projects EME expects to make substantial investments in new projects during the next several years. At June 30, 2008, EME had committed to purchase turbines (as reflected in the above table of capital expenditures) for wind projects that aggregate 1,061 MW. The turbine commitments generally represent approximately two-thirds of the
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Table of Contentstotal capital costs of EME’s wind projects. As of June 30, 2008, EME had a development pipeline of potential wind projects with projected installed capacity of approximately 5,000 MW. The development pipeline represents potential projects with respect to which EME either owns the project rights or has exclusive acquisition rights. Completion of development of a wind project may take a number of years due to factors that include local permit requirements, willingness of local utilities to purchase renewable power at sufficient prices to earn an appropriate rate of return, and availability and prices of equipment. Furthermore, successful completion of a wind project is dependent upon obtaining permits, an interconnection agreement(s) or other agreements necessary to support an investment. There is no assurance that each project included in the development pipeline currently or added in the future will be successfully completed. In addition, a subsidiary of EME was awarded through a competitive bidding process a ten-year power sales contract with SCE for the output of the Walnut Creek project. During the second quarter of 2008, EME and its subsidiary entered into an agreement to purchase major equipment for the project included in turbine commitments in the above table. Subject to obtaining approval for the power sales contract, EME intends to construct the project with total installed costs, excluding interest during construction, estimated in the range of $500 million to $600 million. Credit Ratings Overview Credit ratings for EMG’s direct and indirect subsidiaries at June 30, 2008, were as follows:
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. Credit Rating of EMMT The Homer City sale-leaseback documents restrict EME Homer City’s ability to enter into trading activities, as defined in the documents, with EMMT to sell forward the output of the Homer City facilities if EMMT does not have an investment grade credit rating from S&P or Moody’s or, in the absence of those ratings, if it is not rated as investment grade pursuant to EME’s internal credit scoring procedures. These documents include a requirement that the counterparty to such transactions, and EME Homer City, if acting as seller to an unaffiliated third party, be investment grade. EME currently sells all the output from the Homer City facilities through EMMT, which has a below investment grade credit rating, and EME Homer City is not rated. Therefore, in order for EME to continue to sell forward the output of the Homer City facilities, either: (1) EME must obtain consent from the sale-leaseback owner participant to permit EME Homer City to sell directly into the market or through EMMT; or (2) EMMT must provide assurances of performance consistent with the requirements of the sale-leaseback documents. EME has obtained a consent from the sale-leaseback owner participant that will allow EME Homer City to enter into such sales, under specified conditions, through December 31, 2008. EME Homer City continues to be in compliance with the terms of the consent. EME is permitted to sell the output of the
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Table of ContentsHomer City facilities into the spot market at any time. See “EMG: Market Risk Exposures—Commodity Price Risk—Energy Price Risk Affecting Sales from the Homer City Facilities.” Margin, Collateral Deposits and Other Credit Support for Energy Contracts In connection with entering into contracts in support of EME’s hedging and energy trading activities (including forward contracts, transmission contracts and futures contracts), EME’s subsidiary, EMMT, has entered into agreements to mitigate the risk of nonperformance. EME has entered into guarantees in support of EMMT’s hedging and trading activities; however, because the credit ratings of EMMT and EME are below investment grade, EME has historically also provided collateral in the form of cash and letters of credit for the benefit of counterparties related to accounts payable and unrealized losses in connection with these hedging and trading activities. At June 30, 2008, EMMT had deposited $51 million in cash with brokers in margin accounts in support of futures contracts and had deposited $126 million with counterparties in support of forward energy and transmission contracts. In addition, EME had issued letters of credit of $1 million in support of commodity contracts at June 30, 2008. Future cash collateral requirements may be higher than the margin and collateral requirements at June 30, 2008, if wholesale energy prices increase or the amount hedged increases. EME estimates that margin and collateral requirements for energy contracts outstanding as of June 30, 2008 could increase by approximately $360 million over the remaining life of the contracts using a 95% confidence level. Midwest Generation has cash on hand and a $500 million working capital facility to support margin requirements specifically related to contracts entered into by EMMT related to the Illinois plants. At June 30, 2008, Midwest Generation had available $447 million of borrowing capacity under this credit facility. As of June 30, 2008, Midwest Generation had $151 million in loans receivable from EMMT for margin advances. In addition, EME has cash on hand and $521 million of borrowing capacity available under a $600 million working capital facility to provide credit support to subsidiaries. Dividend Restrictions in Major Financings General Each of EME’s direct or indirect subsidiaries is organized as a legal entity separate and apart from EME and its other subsidiaries. Assets of EME’s subsidiaries are not available to satisfy EME’s obligations or the obligations of any of its other subsidiaries. However, unrestricted cash or other assets that are available for distribution may, subject to applicable law and the terms of financing arrangements of the parties, be advanced, loaned, paid as dividends or otherwise distributed or contributed to EME or to its subsidiary holding companies. Key Ratios of EMG’s Principal Subsidiaries Affecting Dividends Set forth below are key ratios of EME’s principal subsidiaries required by financing arrangements at June 30, 2008 or for the 12 months ended June 30, 2008:
Edison Capital’s ability to make dividend payments is currently restricted by covenants in its financial instruments, which require Edison Capital, through a wholly owned subsidiary, to maintain a specified minimum net worth of $200 million. Edison Capital satisfied this minimum net worth requirement as of June 30, 2008.
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Table of ContentsFor 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—Dividend Restrictions in Major Financings” in the year-ended 2007 MD&A. EMG: OTHER DEVELOPMENTS PJM Matters On April 4, 2008, the FERC issued an order rejecting PJM’s request to revise its RPM to reflect PJM’s claimed rise in its CONE values. CONE is one of the two components used by PJM to determine its Variable Resource Requirement curve for the RPM auction. PJM also proposed to add a new section to its tariff permitting PJM to unilaterally request a CONE increase for use in its May 2008 RPM auction for the 2011/2012 delivery year. In rejecting the proposal, the FERC found that PJM had not met timing provisions in its existing tariff to provide sufficient time for stakeholder review of the analysis and advance planning and that it had also failed to establish that its proposal to revise that provision was necessary on a one-time emergency basis to ensure reliable service. The effect of FERC’s actions on future RPM auctions cannot be determined at this time. The CONE as established for the May 2008 RPM auction for the 2011/2012 delivery year is lower than the PJM request. RPM Buyers’ Complaint On May 30, 2008, a group of entities referring to themselves as the “RPM Buyers” filed a complaint at the FERC asking that PJM’s RPM, as implemented through the transitional base residual auctions establishing capacity payments for the period from June 1, 2008 through May 31, 2011, be found to have produced unjust and unreasonable capacity prices. The RPM Buyers alleged that the absence of price discipline provided by new capacity resources, together with the ability of existing resources to withhold some capacity within the RPM rules, produced capacity prices in the transition period that are not comparable to those that would have been produced in a competitive market or determined under cost-based regulation, and have requested that the FERC order refunds based on that difference. On July 10, 2008, EME responded to the RPM Buyers’ complaint asking that the same be dismissed based upon various legal precedents. In particular EME argued that the complaint represents little more than a collateral attack on the FERC’s orders approving the RPM settlement and rules and that all of the major factors the RPM Buyers alleged produced unjust and unreasonable prices in the base residual auctions were previously litigated and adjudicated in the contested proceedings involving the RPM settlement. A number of other parties, including PJM, also responded to the RPM Buyers’ complaint asking that the same be dismissed. This matter is currently pending before the FERC. EME cannot predict the outcome of this matter. EME Homer City New Source Review Notice of Violation On June 12, 2008, EME Homer City received an NOV from the US EPA alleging that, beginning in 1988, EME Homer City (or former owners of the Homer City facilities) performed repair or replacement projects at Homer City Units 1 and 2 without first obtaining construction permits as required by the Prevention of Significant Deterioration requirements of the Clean Air Act. The US EPA also alleges that EME Homer City has failed to file timely and complete Title V permits. EME Homer City intends to meet with the US EPA to discuss the alleged violations. EME Homer City is investigating the claims made by the US EPA in the NOV and potential responses and cannot predict at this time what effect this matter may have on its facilities, its results of operations, financial position or cash flows. EME 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 EME Homer City acquired the Homer City facilities. The sellers responded by denying the indemnity obligation, but accepting the defense of the claims.
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Table of ContentsEMG: MARKET RISK EXPOSURES Introduction EMG’s primary market risk exposures are associated with the sale of electricity and capacity from, and the procurement of fuel for, its merchant power plants. These market risks arise from fluctuations in electricity, capacity and fuel prices, emission allowances, and transmission rights. Additionally, EME’s financial results can be affected by fluctuations in interest rates. EME manages these risks in part by using derivative financial instruments in accordance with established policies and procedures. Commodity Price Risk Introduction EME’s merchant operations expose it to commodity price risk, which represents the potential loss that can be caused by a change in the market value of a particular commodity. Commodity price risks are actively monitored by a risk management committee to ensure compliance with EME’s risk management policies. Policies are in place which define risk management processes, and procedures exist which allow for monitoring of all commitments and positions with regular reviews by EME’s risk management committee. Despite this, there can be no assurance that all risks have been accurately identified, measured and/or mitigated. In addition to prevailing market prices, EME’s ability to derive profits from the sale of electricity will be affected by the cost of production, including costs incurred to comply with environmental regulations. The costs of production of the units vary and, accordingly, depending on market conditions, the amount of generation that will be sold from the units is expected to vary. EME uses “earnings at risk” to identify, measure, monitor and control its overall market risk exposure with respect to hedge positions at the Illinois plants, the Homer City facilities, and the merchant wind projects, and “value at risk” to identify, measure, monitor and control its overall risk exposure in respect of its trading positions. The use of these measures allows management to aggregate overall commodity risk, compare risk on a consistent basis and identify the risk factors. Value at risk measures the possible loss, and earnings at risk measures the potential change in value of an asset or position, in each case over a given time interval, under normal market conditions, at a given confidence level. Given the inherent limitations of these measures and reliance on a single type of risk measurement tool, EME supplements these approaches with the use of stress testing and worst-case scenario analysis for key risk factors, as well as stop-loss limits and counterparty credit exposure limits. Hedging Strategy To reduce its exposure to market risk, EME hedges a portion of its electricity sales through EMMT, an EME subsidiary engaged in the power marketing and trading business. To the extent that EME does not hedge its electricity sales, the unhedged portion will be subject to the risks and benefits of spot market price movements. Hedge transactions are primarily implemented through:
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Table of ContentsThe extent to which EME hedges its market price risk depends on several factors. First, EME evaluates over-the-counter market prices to determine whether the types of hedge transactions set forth above at forward market prices are sufficiently attractive compared to assuming the risk associated with fluctuating spot market sales. Second, EME’s ability to enter into hedging transactions depends upon its and Midwest Generation’s credit capacity and upon the forward sales markets having sufficient liquidity to enable EME to identify appropriate counterparties for hedging transactions. In the case of hedging transactions related to the generation and capacity of the Illinois plants, Midwest Generation is permitted to use its working capital facility and cash on hand to provide credit support for these hedging transactions entered into by EMMT under an energy services agreement between Midwest Generation and EMMT. Utilization of this credit facility in support of hedging transactions provides additional liquidity support for implementation of EME’s contracting strategy for the Illinois plants. In addition, Midwest Generation may grant liens on its property in support of hedging transactions associated with the Illinois plants. In the case of hedging transactions related to the generation and capacity of the Homer City facilities, credit support is provided by EME pursuant to intercompany arrangements between it and EMMT. See “—Credit Risk” below. Energy Price Risk Affecting Sales from the Illinois Plants All the energy and capacity from the Illinois plants is sold under terms, including price 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. As discussed further below, power generated at the Illinois plants is generally sold into the PJM market. Midwest Generation sells its power into PJM at spot prices based upon locational marginal pricing. Hedging transactions related to the generation of the Illinois plants are generally entered into at the Northern Illinois Hub or the AEP/Dayton Hub, both in PJM, or may be entered into at other trading hubs, including the Cinergy Hub in the Midwest Independent Transmission System Operator (MISO). These trading hubs have been the most liquid locations for hedging purposes. See “—Basis Risk” below for further discussion. PJM has a short-term market, which establishes an hourly clearing price. The Illinois plants are situated in the PJM control area and are physically connected to high-voltage transmission lines serving this market. The following table depicts the average historical market prices for energy per megawatt-hour during the first six months of 2008 and 2007.
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Table of ContentsForward market prices at the Northern Illinois 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 Illinois plants into these markets may vary materially from the forward market prices set forth in the table below. The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the Northern Illinois Hub at June 30, 2008:
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Table of ContentsThe following table summarizes Midwest Generation’s hedge position at June 30, 2008:
Energy Price Risk Affecting Sales from the Homer City Facilities All the energy and capacity from the Homer City facilities is sold under terms, including price 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. Electric power generated at the Homer City facilities is generally sold into the PJM market. PJM has a short-term market, which establishes an hourly clearing price. The Homer City facilities are situated in the PJM control area and are physically connected to high-voltage transmission lines serving both the PJM and NYISO markets.
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Table of ContentsThe following table depicts the average historical market prices for energy per megawatt-hour at the Homer City busbar and in PJM West Hub (EME Homer City’s primary trading hub) during the first six months of 2008 and 2007:
Forward market prices at the 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 Homer City facilities into these markets may vary materially from the forward market prices set forth in the table below. The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at June 30, 2008:
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Table of ContentsThe following table summarizes EME Homer City’s hedge position at June 30, 2008:
The average price/MWh for EME Homer City’s hedge position is based on PJM West Hub. Energy prices at the Homer City busbar have been lower than energy prices at the PJM West Hub. See “—Basis Risk” below for a discussion of the difference. Capacity Price Risk On June 1, 2007, PJM implemented the RPM for capacity. The purpose of the RPM is to provide a long-term pricing signal for capacity resources. The RPM provides a mechanism for PJM to satisfy the region’s need for generation capacity, the cost of which is allocated to load-serving entities through a locational reliability charge. The following table summarizes the status of capacity sales for Midwest Generation and EME Homer City at June 30, 2008:
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Table of ContentsRevenue from the sale of capacity from Midwest Generation and EME Homer City beyond the periods set forth above will depend upon the amount of capacity available and future market prices either in PJM or nearby markets if EME has an opportunity to capture a higher value associated with those markets. Under PJM’s RPM system, the market price for capacity is generally determined by aggregate market-based supply conditions and an administratively set aggregate demand curve. Among the factors influencing the supply of capacity in any particular market are plant forced outage rates, plant closings, plant delistings (due to plants being removed as capacity resources and/or to export capacity to other markets), capacity imports from other markets, and the CONE. Midwest Generation entered into hedge transactions in advance of the RPM auctions with counterparties that are settled through PJM. In addition, the load service requirements contracts entered into by Midwest Generation with Commonwealth Edison include energy, capacity and ancillary services (sometimes referred to as a “bundled product”). Under PJM’s business rules, Midwest Generation sells all of its available capacity (defined as unit capacity less forced outages) into the RPM and is subject to a locational reliability charge for the load under these contracts. This means that the locational reliability charge generally offsets the related amounts sold in the RPM, which Midwest Generation presents on a net basis in the table above. Prior to the RPM auctions for the relevant delivery periods, EME Homer City sold a portion of its capacity to an unrelated third party for the delivery period of June 1, 2008 through May 31, 2009. EME Homer City is not receiving the RPM auction clearing price for this previously sold capacity. The price EME Homer City is receiving for these capacity sales is a function of NYISO capacity clearing prices resulting from separate NYISO capacity auctions. Basis Risk Sales made from the Illinois plants and the Homer City facilities in the real-time or day-ahead market receive the actual spot prices or day-ahead prices, as the case may be, at the busbars (delivery points) of the individual plants. In order to mitigate price risk from changes in spot prices at the individual plant busbars, EME may enter into cash settled futures contracts as well as forward contracts with counterparties for energy to be delivered in future periods. Currently, a liquid market for entering into these contracts at the individual plant busbars does not exist. A liquid market does exist for settlement points at the PJM West Hub in the case of the Homer City facilities and for a settlement point at the Northern Illinois Hub and the AEP/Dayton Hub in the case of the Illinois plants. EME’s hedging activities use these settlement points (and, to a lesser extent, other similar trading hubs) to enter into hedging contracts. EME’s revenue with respect to such forward contracts includes:
Under PJM’s market design, locational marginal pricing, which establishes market prices at specific locations throughout PJM by considering factors including generator bids, load requirements, transmission congestion and losses, can cause the price of a specific delivery point to be higher or lower relative to other locations depending on how the point is affected by transmission constraints. Effective June 1, 2007, PJM implemented marginal losses which adjust the algorithm that calculates locational marginal prices to include a component for marginal transmission losses in addition to the component included for congestion. To the extent that, on the settlement date of a hedge contract, spot prices at the relevant busbar are lower than spot prices at the settlement point, the proceeds actually realized from the related hedge contract are effectively reduced by the difference. This is referred to as “basis risk.” During the six months ended June 30, 2008, 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 14%, compared to 13% during the six months ended June 30, 2007. The monthly average difference during the
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Table of Contents12 months ended June 30, 2008 ranged from 7% to 22%. In contrast to the Homer City facilities, during the past 12 months, the prices at the Northern Illinois Hub were substantially the same as those at the individual busbars of the Illinois plants, although the implementation of marginal losses on June 1, 2007 has lowered energy prices at the Illinois plants busbars. By entering into cash settled futures contracts and forward contracts using the PJM West Hub, the Northern Illinois Hub, and the AEP/Dayton Hub (or other similar trading hubs) as settlement points, EME is exposed to basis risk as described above. In order to mitigate basis risk, EME may purchase financial transmission rights and basis swaps in PJM for EME Homer City. A financial transmission right is a financial instrument that entitles the holder to receive the difference of actual spot prices for two delivery points in exchange for a fixed amount. Accordingly, EME’s hedging activities include using financial transmission rights alone or in combination with forward contracts and basis swap contracts to manage basis risk. Coal and Transportation Price Risk The Illinois plants and the Homer City facilities purchase coal primarily obtained 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 extending through 2011. The following table summarizes the amount of coal under contract at June 30, 2008 for the remainder of 2008 and the following three years.
EME is subject to price risk for purchases of coal that are not under contract. Prices of Northern Appalachian coal, which are related to the price of coal purchased for the Homer City facilities, increased substantially during 2008 from 2007 year-end prices. The price of Northern Appalachian coal (with 13,000 Btu per pound heat content and <3.0 pounds of SO2 per MMBtu sulfur content) increased to $149 per ton at July 25, 2008 from $55.25 per ton at December 21, 2007, 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 Illinois plants increased during 2008 from 2007 year-end prices. The price of PRB coal increased to $12.50 per ton at July 25, 2008 from $11.50 per ton at December 21, 2007, as reported by the Energy Information Administration. The 2008 increase in North Appalachian coal prices were primarily attributable to: 1) increased international and Atlantic basin coal demand, 2) port and rail infrastructure problems and monsoon flooding in Australia, 3) a record cold winter in China, and 4) an energy crisis in South Africa. EME has contractual agreements for the transport of coal to its facilities. The primary contract is with Union Pacific Railroad (and various delivering carriers), which extends through 2011. EME is exposed to price risk related to higher transportation rates after the expiration of its existing transportation contracts. Current transportation rates for PRB coal are higher than the existing rates under contract (transportation costs are more than 50% of the delivered cost of PRB coal to the Illinois plants). Emission Allowances Price Risk The federal Acid Rain Program requires electric generating stations to hold SO2 allowances, and Illinois and Pennsylvania regulations implemented the federal NOX SIP Call requirement. As part of the acquisition of the
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Table of ContentsIllinois plants and the Homer City facilities, EME obtained the rights to the emission allowances that have been or are allocated to these plants. EME purchases (or sells) emission allowances based on the amounts required for actual generation in excess of (or less than) the amounts allocated under these programs. The average price of purchased SO2 allowances decreased to $309 per ton during the first six months of 2008 from $512 per ton during 2007. The price of SO2 allowances, determined by obtaining broker quotes and information from other public sources, was $330 per ton as of June 30, 2008. Following the District of Columbia Circuit Court of Appeals’ decision in July 2008, discussed above under “Other Developments—Environmental Matters—Air Quality Regulation—Clean Air Interstate Rule,” the price of SO2 allowances has further declined. For a discussion of environmental regulations related to emissions, refer to “Other Developments—Environmental Matters” in the year-ended 2007 MD&A. Accounting for Energy Contracts EME uses a number of energy contracts to manage exposure from changes in the price of electricity, including forward sales and purchases of physical power and forward price swaps which settle only on a financial basis (including futures contracts). EME follows SFAS No. 133, and under this Standard these energy contracts are generally defined as derivative financial instruments. Importantly, SFAS No. 133 requires changes in the fair value of each derivative financial instrument to be recognized in earnings at the end of each accounting period unless the instrument qualifies for hedge accounting under the terms of SFAS No. 133. For derivatives that do qualify for cash flow hedge accounting, changes in their fair value are recognized in other comprehensive income until the hedged item settles and is recognized in earnings. However, the ineffective portion of a derivative that qualifies for cash flow hedge accounting is recognized currently in earnings. For further discussion of derivative financial instruments, refer to “Critical Accounting Estimates and Policies—Derivative Financial Instruments and Hedging Activities” in the year-ended 2007 MD&A. SFAS No. 133 affects the timing of income recognition, but has no effect on cash flow. To the extent that income varies under SFAS No. 133 from accrual accounting (i.e., revenue recognition based on settlement of transactions), EME records unrealized gains or losses. EME classifies unrealized gains and losses from energy contracts as part of operating revenue. The results of derivative activities are recorded as part of cash flows from operating activities in the consolidated statements of cash flows. The following table summarizes unrealized gains (losses) from non-trading activities for the second quarters of 2008 and 2007 and six months ended June 30, 2008 and 2007:
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