Back to GetFilings.com
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
/X/ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2003
---------------
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
------------------------ -----------------------------
Commission File Number 1-9936
EDISON INTERNATIONAL
(Exact name of registrant as specified in its charter)
California 95-4137452
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue
Rosemead, California 91770
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (626) 302-2222
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 an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date:
Class Outstanding at May 12, 2003
- --------------------------------------- ----------------------------------------
Common Stock, no par value 325,811,206
=======================================================================================================================================
EDISON INTERNATIONAL
INDEX
Page
No.
------
Part I.Financial Information:
Item 1. Consolidated Financial Statements:
Consolidated Statements of Income - Three Months
Ended March 31, 2003 and 2002 1
Consolidated Balance Sheets - March 31, 2003
and December 31, 2002 2
Consolidated Statements of Comprehensive Income -
Three Months Ended March 31, 2003 and 2002 4
Consolidated Statements of Cash Flows - Three Months
Ended March 31, 2003 and 2002 5
Notes to Consolidated Financial Statements 6
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 17
Item 3. Quantitative and Qualitative Disclosures About Market Risk 61
Item 4. Controls and Procedures 61
Part II. Other Information:
Item 1. Legal Proceedings 62
Item 6. Exhibits and Reports on Form 8-K 63
Signatures
Certifications
EDISON INTERNATIONAL
PART I FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended
March 31,
- ---------------------------------------------------------------------------------------------------------------------------------------
In millions, except per-share amounts 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Electric utility $ 1,823 $ 1,906
Nonutility power generation 684 537
Financial services and other 25 45
- ---------------------------------------------------------------------------------------------------------------------------------------
Total operating revenue 2,532 2,488
- ---------------------------------------------------------------------------------------------------------------------------------------
Fuel 334 256
Purchased power 452 255
Provisions for regulatory adjustment clauses - net 305 671
Other operation and maintenance 785 716
Depreciation, decommissioning and amortization 289 242
Property and other taxes 51 39
- ---------------------------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,216 2,179
- ---------------------------------------------------------------------------------------------------------------------------------------
Operating income 316 309
Interest and dividend income 46 116
Equity in income from partnerships and
unconsolidated subsidiaries - net 60 51
Other nonoperating income 34 17
Interest expense - net of amounts capitalized (299) (359)
Other nonoperating deductions (30) (10)
Dividends on preferred securities (25) (23)
Dividends on utility preferred stock (4) (6)
- ---------------------------------------------------------------------------------------------------------------------------------------
Income from continuing operations before tax 98 95
Income tax 32 16
- ---------------------------------------------------------------------------------------------------------------------------------------
Income from continuing operations 66 79
Income from discontinued operations - net of tax -- 5
- ---------------------------------------------------------------------------------------------------------------------------------------
Income before accounting change 66 84
Cumulative effect of accounting change - net of tax (9) --
- ---------------------------------------------------------------------------------------------------------------------------------------
Net income $ 57 $ 84
- ---------------------------------------------------------------------------------------------------------------------------------------
Weighted-average shares of common stock outstanding 326 326
Basic earnings (loss) per share:
Continuing operations $ 0.20 $ 0.24
Discontinued operations -- 0.02
Cumulative effect of accounting change (0.03) --
- ---------------------------------------------------------------------------------------------------------------------------------------
Total $ 0.17 $ 0.26
- ---------------------------------------------------------------------------------------------------------------------------------------
Weighted-average shares, including effect of dilutive securities 328 329
Diluted earnings (loss) per share:
Continuing operations $ 0.20 $ 0.24
Discontinued operations -- 0.02
Cumulative effect of accounting change (0.03) --
- ---------------------------------------------------------------------------------------------------------------------------------------
Total $ 0.17 $ 0.26
- ---------------------------------------------------------------------------------------------------------------------------------------
Dividends declared per common share -- --
The accompanying notes are an integral part of these financial statements.
Page 1
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
In millions 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
ASSETS
Cash and equivalents $ 2,333 $ 2,468
Restricted cash 50 53
Receivables, less allowances of $37 and $49 for uncollectible
accounts at respective dates 1,114 1,111
Accrued unbilled revenue 414 437
Fuel inventory 104 124
Materials and supplies, at average cost 226 225
Accumulated deferred income taxes - net 151 270
Trading and price risk management assets 48 34
Regulatory assets - net 350 509
Prepayments and other current assets 316 227
- ---------------------------------------------------------------------------------------------------------------------------------------
Total current assets 5,106 5,458
- ---------------------------------------------------------------------------------------------------------------------------------------
Nonutility property - less accumulated provision for
depreciation of $1,018 and $924 at respective dates 7,263 6,923
Nuclear decommissioning trusts 2,147 2,210
Investments in partnerships and unconsolidated subsidiaries 2,058 2,011
Investments in leveraged leases 2,332 2,313
Other investments 340 235
- ---------------------------------------------------------------------------------------------------------------------------------------
Total investments and other assets 14,140 13,692
- ---------------------------------------------------------------------------------------------------------------------------------------
Utility plant, at original cost:
Transmission and distribution 14,334 14,202
Generation 1,460 1,457
Accumulated provision for depreciation and decommissioning (6,237) (8,094)
Construction work in progress 589 529
Nuclear fuel, at amortized cost 144 153
- ---------------------------------------------------------------------------------------------------------------------------------------
Total utility plant 10,290 8,247
- ---------------------------------------------------------------------------------------------------------------------------------------
Goodwill 736 661
Restricted cash 341 406
Regulatory assets - net 3,609 3,838
Other deferred charges 946 921
- ---------------------------------------------------------------------------------------------------------------------------------------
Total deferred charges 5,632 5,826
- ---------------------------------------------------------------------------------------------------------------------------------------
Assets of discontinued operations 16 61
- ---------------------------------------------------------------------------------------------------------------------------------------
Total assets $ 35,184 $ 33,284
- ---------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 2
EDISON INTERNATIONAL
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
In millions, except share amounts 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt $ 127 $ 78
Long-term debt due within one year 1,910 2,761
Preferred stock to be redeemed within one year 9 9
Accounts payable 969 866
Accrued taxes 890 855
Trading and price risk management liabilities 134 45
Other current liabilities 2,097 2,040
- ---------------------------------------------------------------------------------------------------------------------------------------
Total current liabilities 6,136 6,654
- ---------------------------------------------------------------------------------------------------------------------------------------
Long-term debt 12,273 11,557
- ---------------------------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes - net 5,837 5,842
Accumulated deferred investment tax credits 165 167
Customer advances and other deferred credits 1,494 1,841
Power-purchase contracts 259 309
Accumulated provision for pension and benefits 507 461
Asset retirement obligations 2,024 --
Other long-term liabilities 164 161
- ---------------------------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 10,450 8,781
- ---------------------------------------------------------------------------------------------------------------------------------------
Liabilities of discontinued operations 14 72
- ---------------------------------------------------------------------------------------------------------------------------------------
Commitments and contingencies (Notes 2 and 3)
Minority interest 439 425
- ---------------------------------------------------------------------------------------------------------------------------------------
Preferred stock of utility:
Not subject to mandatory redemption 129 129
Subject to mandatory redemption 141 147
Company-obligated mandatorily redeemable securities of subsidiaries
holding solely parent company debentures 951 951
Other preferred securities 139 131
- ---------------------------------------------------------------------------------------------------------------------------------------
Total preferred securities of subsidiaries 1,360 1,358
- ---------------------------------------------------------------------------------------------------------------------------------------
Common stock (325,811,206 shares outstanding at each date) 1,974 1,973
Accumulated other comprehensive loss (230) (247)
Retained earnings 2,768 2,711
- ---------------------------------------------------------------------------------------------------------------------------------------
Total common shareholders' equity 4,512 4,437
- ---------------------------------------------------------------------------------------------------------------------------------------
Total liabilities and shareholders' equity $ 35,184 $ 33,284
- ---------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 3
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended
March 31,
- ---------------------------------------------------------------------------------------------------------------------------------------
In millions 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income $ 57 $ 84
Other comprehensive income, net of tax:
Foreign currency translation adjustments - net 21 16
Unrealized gain (loss) on cash flow hedges - net (3) 41
Reclassification adjustment for gain
included in net income (1) 1
- ---------------------------------------------------------------------------------------------------------------------------------------
Comprehensive income $ 74 $ 142
- ---------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 4
EDISON INTERNATIONAL
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended
March 31,
- ---------------------------------------------------------------------------------------------------------------------------------------
In millions 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Cash flows from operating activities:
Income from continuing operations, after accounting change, net of tax $ 57 $ 79
Adjustments to reconcile to net cash provided
(used) by operating activities:
Depreciation, decommissioning and amortization 289 242
Other amortization 27 26
Deferred income taxes and investment tax credits 28 (139)
Equity in income from partnerships and unconsolidated
subsidiaries (60) (51)
Income from leveraged leases (21) (28)
Regulatory assets - long-term - net 69 537
Power contracts collateral (39) --
Gas call options (15) (23)
Other assets (48) 19
Other liabilities (22) 104
Changes in working capital:
Receivables and accrued unbilled revenue 41 154
Regulatory assets - short-term - net 159 83
Fuel inventory, materials and supplies -- (2)
Prepayments and other current assets (106) (10)
Accrued interest and taxes 56 422
Accounts payable and other current liabilities 252 (2,482)
Distributions and dividends from unconsolidated entities 30 140
Operating cash flows from discontinued operations (17) (1)
- ---------------------------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by operating activities 680 (930)
- ---------------------------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 215 57
Long-term debt repaid (472) (442)
Bonds remarketed and funds held in trust -- 192
Redemption of preferred securities (5) --
Rate reduction notes repaid (62) (62)
Nuclear fuel financing - net -- (59)
Short-term debt financing - net 133 (688)
Financing cash flows from discontinued operations -- (4)
- ---------------------------------------------------------------------------------------------------------------------------------------
Net cash used by financing activities (191) (1,006)
- ---------------------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (323) (350)
Purchase of power sales agreement -- (80)
Purchase of common stock of acquired companies (275) --
Proceeds from sale of nonutility property -- 49
Net funding of nuclear decommissioning trusts (21) (6)
Distributions from (investments in) partnerships and
unconsolidated subsidiaries (29) 86
Sales of investments in other assets 13 67
Investing cash flows from discontinued operations 4 1
- ---------------------------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities (631) (233)
- ---------------------------------------------------------------------------------------------------------------------------------------
Effect of exchange rate changes on cash 7 (2)
- ---------------------------------------------------------------------------------------------------------------------------------------
Net decrease in cash and equivalents (135) (2,171)
Cash and equivalents, beginning of period 2,468 4,038
- ---------------------------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of period 2,333 1,867
Cash and equivalents - discontinued operations -- (72)
- ---------------------------------------------------------------------------------------------------------------------------------------
Cash and equivalents, continuing operations $ 2,333 $ 1,795
- ---------------------------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 5
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary for a fair
presentation of the financial position, results of operations and cash flows in accordance with accounting principles generally
accepted in the United States for the periods covered by this report. The results of operations for the period ended March 31, 2003
are not necessarily indicative of the operating results for the full year.
The quarterly report should be read in conjunction with Edison International's 2002 Annual Report on Form 10-K 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 2002 Annual Report. Edison International follows the same accounting policies for interim reporting purposes.
Certain prior-period amounts were reclassified to conform to the March 31, 2003 financial statement presentation.
New Accounting Standards
Effective January 1, 2003, Edison International adopted a new accounting standard, Accounting for Asset Retirement Obligations, which
requires entities to record the fair value of a liability for a legal asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related
long-lived asset. Over time, the liability is increased to its present value, and the capitalized cost is depreciated over the
useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount
or incurs a gain or loss upon settlement. However, rate-regulated entities may recognize regulatory assets or liabilities as a
result of timing differences between the recognition of costs in accordance with this standard and the recovery of costs through the
rate-making process. Regulatory assets and liabilities may also be recorded if it is probable that the asset retirement obligation
(ARO) will be recovered through the rate-making process.
Edison International's impact of adopting this standard was:
o Southern California Edison (SCE) adjusted its nuclear decommissioning obligation to reflect the fair value of
decommissioning its nuclear power facilities. SCE also recognized AROs associated with the decommissioning of coal-fired
generation assets.
o At December 31, 2002, SCE had accrued $2.3 billion to decommission its nuclear facilities and $12 million to decommission
its share of a coal-fired generating plant, under accounting principles in effect at that time. Of these amounts, $298 million
to decommission its inactive nuclear facility was recorded in other long-term liabilities, and the remaining $2.0 billion was
recorded as a component of the accumulated provision for depreciation and decommissioning on the consolidated balance sheets in
the 2002 Annual Report.
Page 6
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
o As of January 1, 2003, SCE reversed the $2.3 billion it had previously recorded for decommissioning, recorded the fair value of its
AROs of approximately $2.0 billion in the deferred credits and other liabilities section of the balance sheet, and increased its
unamortized nuclear investment by $303 million. The cumulative effect of a change in accounting principle from unrecognized
accretion expense and adjustments to depreciation, decommissioning and amortization expense recorded to date was a $354 million
after-tax gain, which under accounting standards for rate-regulated enterprises was deferred as a regulatory liability, partially
offset by a $235 million deferred tax asset, as of January 1, 2003. Accretion and depreciation expense resulting from the
application of the new standard is expected to be approximately $143 million in 2003. This cost will reduce the regulatory
liability, with no impact on earnings. As of March 31, 2003, SCE's ARO for its nuclear facilities totaled approximately
$2.0 billion and its nuclear decommissioning trust assets had a fair value of $2.1 billion. If the new standard had been in
place on January 1, 2002, SCE's ARO as of that date would have been $1.98 billion. Approximately $1.9 billion collected through
rates for cost of removal of plant assets not considered to be legal obligations remain in accumulated depreciation and
decommissioning.
o As of January 1, 2003, Edison Mission Energy's (EME) ARO was $17 million and EME recorded a cumulative effect adjustment
that decreased net income by approximately $9 million, net of tax. If the new standard had been applied retroactively in the
three months ended March 31, 2002, it would not have had a material effect on EME's results of operations.
In January 2003, an accounting interpretation was issued to address consolidation of variable-interest entities (VIEs). The primary
objective of the interpretation is to provide guidance on the identification of, and financial reporting for, entities over which
control is achieved through means other than voting rights; such entities are known as VIEs. This interpretation applies to VIEs
created after January 31, 2003 and beginning July 1, 2003 applies to VIEs in which an enterprise holds a variable interest that it
acquired before February 1, 2003.
If an enterprise absorbs the majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns, or
both, it must consolidate the VIE. An enterprise that is required to consolidate the VIE is called the primary beneficiary.
Additional disclosure requirements are also applicable when an enterprise holds a significant variable interest in a VIE, but is not
the primary beneficiary. In addition, financial statements issued after January 31, 2003 must include certain disclosures if it is
reasonably possible that an enterprise will consolidate or disclose information about a VIE when this interpretation is effective.
Edison International has concluded that it is the primary beneficiary in several projects, including EME's Brooklyn Navy Yard project
and Edison Capital's Storm Lake project, since it is at risk with respect to the majority of its losses and is entitled to receive
the majority of its residual returns. Accordingly, effective July 1, 2003, Edison International will consolidate these projects,
which will increase total assets by approximately $447 million and total liabilities by approximately $528 million. Edison
International expects to record a loss of approximately $77 million (of which $71 million is related to Brooklyn Navy Yard) as a
cumulative accounting change as a result of consolidating these VIEs.
Page 7
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Edison International believes it is reasonably possible that certain partnership interests in energy projects are VIEs under this
interpretation, as discussed below:
Edison International owns certain partnership interests in seven energy partnerships, which own a combined 3,098 MW of power plants.
The maximum exposure to loss from EME's interest in these energy partnerships is $1.1 billion at March 31, 2003. Of this amount,
$542 million represents EME's investment in the 1,230 MW Paiton project and $305 million represents EME's investment in the 540 MW
EcoElectrica project.
EME owns a 50% interest in TM Star, which was formed for the limited purpose of selling natural gas to another affiliated project
under a fuel supply agreement. TM Star has entered into fuel purchase contracts with unrelated third parties to meet a portion of
the obligations under the fuel supply agreement. EME has guaranteed 50% of the obligation under the fuel supply agreement to this
affiliated project. The maximum loss is subject to changes in natural gas prices. Accordingly, the maximum exposure to loss cannot
be determined.
Edison International is in the process of reviewing the entities discussed above that have a reasonable possibility of being VIEs to
determine if it is the primary beneficiary.
Stock-Based Employee Compensation
Edison International has three stock-based employee compensation plans, which are described more fully in Note 7 of Edison
International's 2002 Annual Report. Edison International accounts for these plans using the intrinsic value method. Upon grant, no
stock-based employee compensation cost is reflected in net income, as all options granted under those plans had an exercise price
equal to the market value of the underlying common stock on the date of grant. The following table illustrates the effect on net
income and earnings per share if Edison International had used the fair-value accounting method.
Three Months Ended
March 31,
- ---------------------------------------------------------------------------------------------------------------------------------------
In millions 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income, as reported $ 57 $ 84
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 2 2
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 2 1
- ---------------------------------------------------------------------------------------------------------------------------------------
Pro forma net income $ 57 $ 85
- ---------------------------------------------------------------------------------------------------------------------------------------
Basic earnings per share:
As reported $ 0.17 $ 0.26
Pro forma $ 0.17 $ 0.26
Diluted earnings per share:
As reported $ 0.17 $ 0.26
Pro forma $ 0.17 $ 0.26
- ---------------------------------------------------------------------------------------------------------------------------------------
Page 8
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Supplemental Cash Flows Information
Three Months Ended
March 31,
- ---------------------------------------------------------------------------------------------------------------------------------------
In millions 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Non-cash investing and financing activities:
Details of assets acquired:
Fair value of assets acquired $ (333) $ --
Liabilities assumed 58 --
- ---------------------------------------------------------------------------------------------------------------------------------------
Cash paid for acquisitions $ (275) $ --
- ---------------------------------------------------------------------------------------------------------------------------------------
Details of senior secured credit facility transaction:
Retirement of credit facility $ -- $(1,650)
Senior secured credit facility replacement -- 1,600
- ---------------------------------------------------------------------------------------------------------------------------------------
Cash paid on retirement of credit facility $ -- $ (50)
- ---------------------------------------------------------------------------------------------------------------------------------------
Details of long-term debt exchange offer:
Variable rate notes redeemed $ (966) $ --
First and refunding notes issued 966 --
- ---------------------------------------------------------------------------------------------------------------------------------------
Note 2. Regulatory Matters
Further information on regulatory matters, including proceedings for California Department of Water Resources power purchases and
revenue requirements, electric line maintenance practices, generation procurement, Mohave Generating Station, utility-retained
generation, and wholesale electricity markets, is described in Note 2 of "Notes to Consolidated Financial Statements" included in
Edison International's 2002 Annual Report.
California Public Utilities Commission (CPUC) Litigation Settlement Agreement
In 2001, SCE and the CPUC entered into a settlement of SCE's lawsuit against the CPUC, which sought a ruling that SCE is entitled to
full recovery of its past electricity procurement costs. A key element of the settlement agreement was the establishment of a $3.6
billion rate-recovery mechanism called the procurement-related obligations account (PROACT) as of August 31, 2001. The Utility
Reform Network (TURN), a consumer advocacy group, and other parties appealed to the federal court of appeals seeking to overturn the
stipulated judgment of the district court that approved the settlement agreement. On March 4, 2002, the court of appeals heard
argument on the appeal, and on September 23, 2002 the court issued its opinion. In the opinion, the court affirmed the district
court on all claims, with the exception of the challenges founded upon California state law, which the appeals court referred to the
California Supreme Court. In sum, the appeals court concluded that none of the substantive arguments based on federal statutory or
constitutional law compelled reversal of the district court's approval of the stipulated judgment.
However, the appeals court stated in its opinion that there is a serious question whether the settlement agreement violated state
law, both in substance and in the procedure by which the CPUC agreed to it. The appeals court added that if the settlement agreement
violated state law, the CPUC lacked capacity to
Page 9
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
consent to the stipulated judgment, and the stipulated judgment would need to be vacated. The appeals court indicated that, on a
substantive level, the stipulated judgment appears to violate California's electric industry restructuring statute providing for a
rate freeze. The appeals court also indicated that, on a procedural level, the stipulated judgment appears to violate California
laws requiring open meetings and public hearings. Because federal courts are bound by the pronouncements of the state's highest
court on applicable state law, and because the federal appeals court found no controlling precedents from California courts on the
issues of state law in this case, the appeals court issued a separate order certifying those issues in question form to the
California Supreme Court and requested that the California Supreme Court accept certification.
The California Supreme Court accepted the certification, reformulated one of the certified questions as SCE had requested, and set a
briefing schedule that will be followed by oral argument. SCE and the CPUC filed their respective opening briefs on the certified
questions on December 20, 2002. TURN filed its answering brief on January 24, 2003 and SCE and the CPUC filed reply briefs on
February 13, 2003. Various third parties, including the Governor, submitted friend-of-the-court briefs concerning the certified
questions. In addition, the California Supreme Court requested that the parties provide supplemental briefing with respect to an
issue related to California's open meeting laws. The parties have complied with such request. The California Supreme Court has set
oral arguments for May 27, 2003. Once the California Supreme Court rules, the matter will return to the Ninth Circuit, which in turn
should be guided by the California Supreme Court's answers and interpretations of state law. In the meantime, the case is stayed in
the federal appellate court. SCE continues to operate under the settlement agreement, and also continues to believe it is probable
that SCE ultimately will recover its past procurement costs through regulatory mechanisms, including the PROACT. However, SCE cannot
predict with certainty the outcome of the pending legal proceedings.
Holding Company Proceeding
In April 2001, the CPUC issued an order instituting investigation that reopens the past CPUC decisions authorizing utilities to form
holding companies and initiates an investigation into, among other things: whether the holding companies violated CPUC requirements
to give first priority to the capital needs of their respective utility subsidiaries; any additional suspected violations of laws or
CPUC rules and decisions; and whether additional rules, conditions, or other changes to the holding company decisions are necessary.
On January 9, 2002, the CPUC issued an interim decision on the first priority condition. The decision stated that, at least under
certain circumstances, the condition includes the requirement that holding companies infuse all types of capital into their
respective utility subsidiaries when necessary to fulfill the utility's obligation to serve. The decision did not determine if any
of the utility holding companies had violated this condition, reserving such a determination for a later phase of the proceedings.
On February 11, 2002, SCE and Edison International filed an application before the CPUC for rehearing of the decision. On July 17,
2002, the CPUC affirmed its earlier decision on the first priority condition and also denied Edison International's request for a
rehearing of the CPUC's determination that it had jurisdiction over Edison International in this proceeding. On August 21, 2002,
Edison International and SCE jointly filed a petition requesting a review of the CPUC's decisions with regard to first priority
considerations, and Edison International filed a petition for a review of the CPUC decision asserting jurisdiction over holding
companies, both in state court as required. Pacific Gas and Electric and San Diego Gas & Electric and their respective holding
companies filed similar challenges, and all cases have been transferred to the First District Court of Appeals in San Francisco. The
CPUC filed briefs in opposition to the writ petitions. Edison International, SCE and the other petitioners filed reply briefs on
March 6, 2003. No hearings have been scheduled. The court may rule without holding
Page 10
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
hearings. Edison International cannot predict with certainty what effects this investigation or any subsequent actions by the CPUC
may have on Edison International or any of its subsidiaries.
Note 3. 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 results of operations or liquidity.
Aircraft Leases
Edison Capital has leased three aircraft to American Airlines. American Airlines is reporting significant operating losses, and
there is concern that American Airlines may file bankruptcy. If American Airlines files bankruptcy, or otherwise defaults in making
its lease payments, the lenders with a security interest in the aircraft or leases may exercise remedies that could lead to a loss of
some or all of Edison Capital's investment in the aircraft plus any accrued interest. The total maximum loss exposure to Edison
Capital is $48 million. A voluntary restructure of the leases could also result in a loss of some or all of the investment. At
March 31, 2003, American Airlines was current in its lease payments and was publicly expressing a desire to avoid bankruptcy.
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 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.
Edison International's recorded estimated minimum liability to remediate its 43 identified sites at SCE (40 sites) and EME (3 sites)
is $102 million, $100 million of which is related to SCE. The sites include SCE's divested gas-fueled generation plants, for which
SCE retained some liability after their sale. 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
Page 11
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 $290 million, $288 million of which is related to SCE. The upper limit of this range of costs was estimated using
assumptions least favorable to Edison International among a range of reasonably possible outcomes.
The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $39 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 $71 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 $15 million to $30 million. Recorded costs for the twelve months ended March 31, 2003 were
$22 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
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 Income Taxes
In August 2002, Edison International received a notice from the Internal Revenue Service (IRS) asserting deficiencies in federal
corporate income taxes for its 1994 to 1996 tax years. The vast majority of the tax deficiencies are timing differences and,
therefore, amounts ultimately paid, if any, would benefit Edison International as future tax deductions. Edison International
believes that it has meritorious legal defenses to those deficiencies and believes that the ultimate outcome of this matter will not
result in a material impact on Edison International's consolidated results of operations or financial position.
Among the issues raised by the IRS in the 1994 to 1996 audit was Edison Capital's treatment of the EPZ and Dutch electric locomotive
leases. Written protests were filed against these deficiency notices, as well as other alleged deficiencies, asserting that the
IRS's position misstates material facts, misapplies
Page 12
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the law and is incorrect. Edison Capital will contest the assessment through administrative appeals and litigation, if necessary.
Edison Capital believes it will ultimately prevail.
The IRS is also currently examining the tax returns for Edison International, which includes Edison Capital, for years 1997 through
1999. Edison Capital expects the IRS to also challenge several of its other leveraged leases based on a recent Revenue Ruling
addressing a specific type of leveraged lease (termed a lease in/lease out or LILO transaction). Edison Capital believes that the
position described in the Revenue Ruling is incorrectly applied to Edison Capital's transactions and that its leveraged leases are
factually and legally distinguishable in material respects from that position. Edison Capital intends to defend, and litigate if
necessary, against any challenges based on that position.
Navajo Nation Litigation
Peabody Holding Company (Peabody) supplies coal from mines on Navajo Nation lands to Mohave. In June 1999, the Navajo Nation filed a
complaint in the United States District Court for the District of Columbia (D.C. District Court) against Peabody and certain of its
affiliates, Salt River Project Agricultural Improvement and Power District, and SCE. The complaint asserts claims against the
defendants for, among other things, violations of the federal RICO statute, interference with fiduciary duties and contractual
relations, fraudulent misrepresentation by nondisclosure, and various contract-related claims. The complaint claims that the
defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal. The complaint seeks
damages of not less than $600 million, trebling of that amount, and punitive damages of not less than $1 billion, as well as a
declaration that Peabody's lease and contract rights to mine coal on Navajo Nation lands should be terminated.
In February 2002, Peabody and SCE filed cross claims against the Navajo Nation, alleging that the Navajo Nation had breached a
settlement agreement and final award between Peabody and the Navajo Nation by filing their lawsuit.
The Navajo Nation had previously filed suit in the Court of Claims against the United States Department of Interior, alleging that
the Government had breached its fiduciary duty concerning contract negotiations including the Navajo Nation and the defendants. In
February 2000, the Court of Claims issued a decision in the Government's favor, finding that while there had been a breach, there was
no available redress from the Government. Following appeal of that decision by the Navajo Nation, an appellate court ruled that the
Court of Claims did have jurisdiction to award damages and remanded the case to the Court of Claims for that purpose. On June 3,
2002, the Government's request for review of the case by the United States Supreme Court was granted. On March 4, 2003, the Supreme
Court reversed the appellate court and held that the Government is not liable to the Navajo Nation as there was no breach of a
fiduciary duty and that the Navajo Nation did not have a right to relief against the Government. Based on the Supreme Court's
analysis, on April 28, 2003, SCE filed a motion to dismiss or, in the alternative, for summary judgment in the D.C. District Court
action. The motion remains pending.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, nor the impact on this complaint or
the Supreme Court's decision on the outcome of the Navajo Nation's suit against the government, or the impact of the complaint on the
operation of Mohave beyond 2005.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $9.5 billion. SCE and other owners of the San Onofre and Palo
Verde Nuclear Generating Stations have purchased the maximum private
Page 13
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
primary insurance available ($300 million beginning January 1, 2003). 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 U.S. 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 Nuclear Regulatory Commission exempted San Onofre Unit 1 from this secondary level, effective June 1994.
The maximum deferred premium for each nuclear incident is $88 million per reactor, but not more than $10 million per reactor may be
charged in any one year for each incident. Based on its ownership interests, SCE could be required to pay a maximum of $175 million
per nuclear incident. However, it would have to pay no more than $20 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 regulations may impose further revenue-raising measures to pay claims,
including a possible additional assessment on all licensed reactor operators. The U.S. Congress has extended the expiration date of
the applicable law until December 31, 2003 and is considering amendments that, among other things, are expected to extend the law
beyond 2003.
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 arrangement were to exceed the accumulated funds for these insurance programs, SCE could be assessed
retrospective premium adjustments of up to $38 million per year. Insurance premiums are charged to operating expense.
Spent Nuclear Fuel
Under federal law, the U.S. Department of Energy (DOE) is responsible for the selection and development of a facility for disposal of
spent nuclear fuel and high-level radioactive waste. Such a facility was to be in operation by January 1998. However, the DOE did
not meet its obligation. It is not certain when the DOE will begin accepting spent nuclear fuel from San Onofre or from other
nuclear power plants. Extended delays by the DOE could lead to consideration of costly alternatives involving 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(cent)per kWh of
nuclear-generated electricity sold after April 6, 1983.
SCE, as operating agent, has primary responsibility for the interim storage of its spent nuclear fuel at San Onofre. The San Onofre
Units 2 and 3 spent fuel pools currently contain San Onofre Unit 1 spent fuel in addition to spent fuel from Units 2 and 3. Current
capability to store spent fuel in the Units 2 and 3 spent fuel pools is adequate through 2005. SCE plans to move the Unit 1 spent
fuel to an interim spent fuel storage facility by the third quarter of 2003. The spent fuel pool storage capacity for Units 2 and 3
will then accommodate needs until 2007 for Unit 2 and 2008 for Unit 3. SCE expects to begin using an interim spent fuel storage
facility for Units 2 and 3 spent fuel by early 2006. Palo Verde on-site spent fuel storage capacity will accommodate needs until
2003 for Unit 2 and until 2004 for Units 1 and 3. Arizona Public Service Company, operating agent for Palo Verde, expects to begin
using an interim spent fuel storage facility in the first half of 2003.
Page 14
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Storm Lake
As of March 31, 2003, Edison Capital had an investment of approximately $80 million in Storm Lake Power, a project developed by Enron
Wind, a subsidiary of Enron Corporation. As of March 31, 2003, Storm Lake had outstanding loans of approximately $65 million. Enron
and its subsidiary provided certain guarantees related to the amount of power that would be generated from Storm Lake. The lenders
have sent a notice to Storm Lake claiming that Enron's bankruptcy, among other things, is an event of default under the loan
agreement. In the event of default, the lenders may exercise certain remedies, including acceleration of the loan balance,
repossession and foreclosure of the project, which could result in the loss of some or all of Edison Capital's investment in Storm
Lake. While expressly reserving their rights, the lenders have not taken any steps to exercise their remedies beyond issuing the
notices of default. On behalf of Storm Lake, Edison Capital is also engaged in regular, ongoing discussions with the lenders in
which Edison Capital expects to demonstrate to the lenders that Storm Lake's ability to meet its loan obligations is not impaired and
that the noticed events of default can be worked out with the lenders. Edison Capital believes that Storm Lake will oppose any
attempt by the lenders to exercise remedies that could result in a loss of Edison Capital's investment.
Note 4. Business Segments
Edison International's reportable business segments include its electric utility operation segment (SCE), an unregulated power
generation segment (EME), and a capital and financial services provider segment (Edison Capital).
Segment information for the three months ended March 31, 2003 and 2002 was:
Three Months Ended
March 31,
- -----------------------------------------------------------------------------------------------------------------------------------
In millions 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Operating Revenue:
Electric utility $ 1,823 $ 1,906
Unregulated power generation 684 537
Capital & financial services 21 31
Corporate and other 4 14
- -----------------------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 2,532 $ 2,488
- -----------------------------------------------------------------------------------------------------------------------------------
Net Income (Loss):
Electric utility(1) $ 102 $ 146
Unregulated power generation(2) (17) (36)
Capital & financial services 15 19
Corporate and other (43) (45)
- -----------------------------------------------------------------------------------------------------------------------------------
Consolidated Edison International $ 57 $ 84
- -----------------------------------------------------------------------------------------------------------------------------------
(1) Net income available for common stock.
(2) Includes a loss of $9 million from the cumulative effect of an accounting change for the three months ended March 31, 2003.
Also, includes earnings from discontinued operations of $5 million for the three months ended March 31, 2002.
Page 15
EDISON INTERNATIONAL
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Corporate and other includes amounts from nonutility subsidiaries not significant as a reportable segment. The net loss of
$43 million and $45 million, respectively, reported for the three months ended March 31, 2003 and 2002, also includes Mission Energy
Holding Company's net loss of $24 million and $22 million, respectively, for the same periods.
Total segment assets as of March 31, 2003 were: electric utility, $20 billion; unregulated power generation, $12 billion; and,
capital and financial services, $4 billion.
Note 5. Acquisitions and Dispositions
On March 3, 2003, Contact Energy, EME's 51% owned subsidiary, completed a transaction with NGC Holdings Ltd. to acquire the Taranaki
combined cycle power station and related interests. Consideration for the Taranaki station consisted of a cash payment of
approximately $275 million, which was financed with bridge loan facilities. The bridge loan facilities were subsequently repaid with
proceeds from the issuance of long-term U.S. dollar denominated notes. The Taranaki station is a 357 MW combined cycle, natural
gas-fired plant located near Statford, New Zealand.
During the first quarter of 2002, EME completed the sales of its 50% interests in the Commonwealth Atlantic and James River projects
and its 30% interest in the Harbor project. Proceeds received from the sales were $44 million. During 2001, EME recorded asset
impairment charges of $32 million related to these projects based on the expected sales proceeds. No gain or loss was recorded from
the sale of EME's interests in these projects during the first quarter of 2002.
Note 6. Discontinued Operations
The results of the Lakeland project, the Fiddler's Ferry and Ferrybridge coal stations and Edison Enterprises subsidiaries sold
during 2001 have been reflected as discontinued operations in the consolidated financial statements in accordance with an accounting
standard related to the impairment and disposal of long-lived assets. The consolidated financial statements have been restated to
conform to the discontinued operations presentation for both periods presented. For the three months ended March 31, 2002, revenue
from discontinued operations was $21 million and pre-tax income was $5 million.
Note 7. Subsequent Event
On April 16, 2003, SCE fully repaid a $300 million senior secured credit facility. This revolver was secured by first and refunding
mortgage bonds. SCE may draw upon the $300 million available credit until the agreement expires on March 1, 2004.
Page 16
Item 2. Management's Discussion and Analysis of Results of Operations and
Financial Condition
This Management's Discussion and Analysis of Results of Operations and Financial Condition (MD&A) for the first quarter of 2003
discusses material changes in the results of operations, financial condition and other developments of Edison International since
December 31, 2002 and as compared to the first quarter of 2002. This discussion presumes that the reader has read or has access to
Edison International's MD&A for the calendar year 2002 (the year-ended 2002 MD&A), which was included in Edison International's 2002
annual report to shareholders and incorporated by reference into Edison International's Annual Report on Form 10-K for the year ended
December 31, 2002.
This MD&A contains forward-looking statements. These statements are based on Edison International's knowledge of present facts,
current expectations about future events and assumptions about future developments. Forward-looking statements are not guarantees of
performance; they are subject to risks, uncertainties and assumptions that could cause actual future activities and results of
operations to be materially different from those set forth in this MD&A. Important factors that could cause actual results to differ
include, but are not limited to, risks discussed below under "Financial Condition," "Market Risk Exposures" and "Forward-Looking
Information and Risk Factors." The following discussion provides updated information about material developments since the issuance
of the year-ended 2002 MD&A and should be read in conjunction with the financial statements contained in this quarterly report and
Edison International's Annual Report on Form 10-K for the year ended December 31, 2002.
This MD&A includes information about Edison International and its principal subsidiaries, Southern California Edison Company (SCE),
Edison Mission Energy (EME), Edison Capital and Mission Energy Holding Company (MEHC). Edison International is a holding company.
SCE is a regulated public utility company providing electricity to retail customers in central, coastal, and southern California.
EME is an independent power producer engaged in owning or leasing and operating electric power generation facilities worldwide and in
energy trading and price risk management activities. Edison Capital is a global provider of capital and financial services in
energy, affordable housing, and infrastructure projects focusing primarily on investments related to the production and delivery of
electricity. MEHC was formed in June 2001, as a holding company for EME. In this MD&A, except when stated to the contrary,
references to each of Edison International, SCE, MEHC, 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. References to SCE, MEHC, EME or Edison Capital followed by (stand alone) mean each such
company alone, not consolidated with its subsidiaries.
CURRENT DEVELOPMENTS
SCE Developments
As discussed in detail in "SCE's Regulatory Matters--CPUC Litigation Settlement Agreement," SCE entered into a settlement agreement
with the California Public Utilities Commission (CPUC) that allowed SCE to recover $3.6 billion in past procurement-related costs.
The Utility Reform Network (TURN), a consumer advocacy group, and other parties appealed to the federal court seeking to overturn the
district court judgment that approved the settlement agreement. In September 2002, an appeals court opinion affirmed the district
court on all claims, with the exception of challenges founded upon California state law, which the appeals court referred to the
California Supreme Court. On November 20, 2002, the California Supreme Court issued an order indicating that it would hear the case
and has scheduled oral arguments for May 27, 2003.
Page 17
MEHC and EME Developments
A number of significant developments during late 2001 and 2002 adversely affected independent power producers and subsidiaries of
major integrated energy companies that sell a sizable portion of their generation into the wholesale energy market (sometimes
referred to as merchant generators), including several of EME's subsidiaries. These developments included lower market prices in
wholesale energy markets both in the United States and United Kingdom, significant declines in the credit ratings of most major
market participants, decreased availability of debt financing or refinancing, and a resulting decline of liquidity in the energy
markets due to growing concern about the ability of counterparties to perform their obligations. Since the beginning of 2003,
several merchant generators reached agreements to extend existing bank credit facilities.
EME's largest subsidiary, Edison Mission Midwest Holdings has $911 million of debt maturing in December 2003, which will need to be
repaid, extended or refinanced. Edison Mission Midwest Holdings is not expected to have sufficient cash to repay the $911 million
debt due in December 2003, and there is no assurance that Edison Mission Midwest Holdings will be able to extend or refinance its
debt obligation on similar terms and rates as the existing debt, on commercially reasonable terms, on the terms permitted under the
financing documents entered into by MEHC in July 2001, or at all. The independent accountants' audit opinions on the year-end 2002
financial statements of MEHC, EME and Midwest Generation contain an explanatory paragraph that indicates the consolidated financial
statements have been prepared on the basis that these companies will continue as going concerns and that the uncertainty about Edison
Mission Midwest Holdings' ability to repay, extend, or refinance this obligation raises substantial doubt about their ability to
continue as going concerns. Accordingly, the consolidated financial statements do not include any adjustments that might result from
the resolution of this uncertainty.
RESULTS OF OPERATIONS
First Quarter 2003 vs. First Quarter 2002
Edison International recorded earnings of $57 million or 17(cent)per share for the first quarter 2003, compared to $84 million or 26(cent)per
share for the first quarter 2002. The table below presents Edison International's earnings per share and net income for the first
quarters of 2003 and 2002, and the relative contributions by its subsidiaries.
In millions, except per share amounts EPS Earnings (Loss)
- ---------------------------------------------------------------------------------------------------------------------------------------
Three Months Ended March 31, 2003 2002 2003 2002
- ---------------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations:
SCE $ 0.31 $ 0.45 $ 102 $ 146
EME (0.02) (0.13) (8) (41)
Edison Capital 0.04 0.06 15 19
Mission Energy Holding Company (stand alone) (0.07) (0.07) (24) (22)
Edison International (parent) and other (0.06) (0.07) (19) (23)
- ---------------------------------------------------------------------------------------------------------------------------------------
Earnings from Continuing Operations 0.20 0.24 66 79
Earnings from Discontinued Operations -- 0.02 -- 5
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings before
Cumulative Effect of Accounting Change 0.20 0.26 66 84
- ---------------------------------------------------------------------------------------------------------------------------------------
Cumulative Effect of Accounting Change (0.03) -- (9) --
- ---------------------------------------------------------------------------------------------------------------------------------------
Edison International Consolidated Earnings $ 0.17 $ 0.26 $ 57 $ 84
- ---------------------------------------------------------------------------------------------------------------------------------------
Earnings (Loss) from Continuing Operations
Edison International's first quarter 2003 earnings from continuing operations were $66 million or 20(cent)per share, compared with
earnings of $79 million or 24(cent)per share for first quarter 2002.
Page 18
SCE earned $102 million in the first quarter of 2003, compared with $146 million in the same period last year. The $44 million
decrease primarily reflects a planned refueling outage at San Onofre Nuclear Generating Station (San Onofre) during the first quarter
of 2003. The decrease also includes higher operating and maintenance expenses from higher health-care costs and storm-damage
expenses, partially offset by higher performance-based ratemaking (PBR) revenue due to an April 22, 2002 CPUC decision that modified
the PBR mechanism (see "SCE's Regulatory Matters--PBR Decision" in the year-ended 2002 MD&A for further discussion).
In January 2002, the CPUC approved the creation of the procurement-related obligations account (PROACT) to record the recovery of
$3.6 billion of SCE's procurement-related obligations pursuant to the settlement agreement between SCE and the CPUC. In February
2003, the CPUC allowed SCE to transfer $209 million into its PROACT for natural gas hedging costs. The remaining PROACT balance was
$640 million as of March 31, 2003 and $512 million as of April 30, 2003.
EME's first quarter 2003 loss from continuing operations was $8 million compared to a loss of $41 million in the same period last
year. The reduced loss of $33 million was primarily due to higher U.S. energy prices in the first quarter of 2003 compared to 2002.
EME's earnings are seasonal with higher earnings expected during the summer months.
Edison Capital's earnings for the first quarter of 2003 were $15 million, down $4 million from the same period last year. This
decrease was primarily due to a maturing investment portfolio, which produces lower income, partially offset by lower net interest
expense and higher tax benefits.
Edison International (parent company) and other incurred a loss of $19 million reflecting an improvement of $4 million over the prior
year's period. The improvement was primarily due to the absence of 2002 losses from a nonutility subsidiary providing operation and
maintenance services to independent power companies, resulting from Edison International's decision to wind down the business in 2003.
Operating Revenue
Approximately 93% of electric utility revenue was from retail sales. Retail rates are regulated by the CPUC and wholesale rates are
regulated by the Federal Energy Regulatory Commission (FERC).
Due to warmer weather and higher electricity usage during the summer months, electric utility revenue during the third quarter of
each year is significantly higher than other quarters.
Electric utility revenue decreased in 2003 primarily due to an allocation adjustment for the California Department of Water Resources
(CDWR) energy purchases and remittance of CDWR bond related charges, partially offset by an increase in revenue from lower credits
given to direct access customers (1.7(cent)per kWh decrease as discussed below).
Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's customers (beginning
January 17, 2001), CDWR bond-related costs (beginning November 15, 2002) and direct access exit fees (beginning January 1, 2003) are
remitted to the CDWR and are not recognized as revenue by SCE. These amounts were $424 million and $341 million for the three months
ended March 31, 2003 and 2002, respectively.
From 1998 through mid-September 2001, SCE's customers were able to choose to purchase power directly from an energy service provider
other than SCE (thus becoming direct access customers) or continue to have SCE purchase power on their behalf. On March 21, 2002,
the CPUC issued a decision affirming that
Page 19
new direct access arrangements entered into by SCE's customers after September 20, 2001 were invalid. Direct access arrangements
entered into prior to September 20, 2001 remain valid. Direct access customers continue to be given a credit, currently 7.5(cent)per
kWh, for the generation costs SCE saves by not serving them. Effective July 27, 2002, the CPUC reduced the direct access credit by
2.7(cent)per kWh to collect a nonbypassable historical procurement charge. Beginning on January 1, 2003, the contribution by direct
access customers to SCE was reduced to 1(cent)per kWh, with the remaining 1.7(cent)per kWh allocated to the CDWR for its costs associated
with direct access customers. Electric utility revenue is reported net of this credit. See "SCE's Regulatory Matters--Direct Access
Proceedings" discussion below.
Nonutility power generation revenue increased in 2003 primarily due to increased electric revenue from EME's Homer City facilities,
Contact Energy and Illinois plants. The increase at EME's Homer City facilities and Contact Energy were primarily due to increased
generation and higher energy and wholesale electricity prices. In addition, Homer City experienced an unplanned outage in the first
quarter of 2002. The increase at EME's Illinois plants was primarily due to increased generation at its coal plants and Collins
Station and higher average realized energy prices.
In accordance with power purchase agreements, Exelon Generation released 4,548 MW of generating capacity during 2002 from the power
purchase agreements at EME's Illinois plants. Of the generating capacity released by Exelon Generation, EME's subsidiary suspended
operations for 1,370 MW and decommissioned 45 MW. As a result, beginning in 2003, EME's Illinois plants have 3,133 MW available for
sale as merchant energy. Exelon Generation is obligated, under the power purchase agreements, to make capacity payments for the
Illinois plants under contract (4,739 MW during 2003) and an energy payment for electricity produced by these plants. As a result of
the decline in contracted generating capacity under the power purchase agreements, EME's revenue from Exelon Generation was $131
million and $161 million for the first quarters of 2003 and 2002, respectively. This represents 19% and 30% of nonutility power
generation revenue for the first quarters of 2003 and 2002, respectively. See "Illinois Plants" discussion in "Market Risk
Exposures--EME's Market Risks--Commodity Price Risk."
Nonutility power generation revenue during the third quarter is materially higher than other quarters of the year because warmer
weather during the summer months results in higher revenue being generated from EME's Homer City facilities and Illinois plants. By
contrast, EME's First Hydro plants have higher revenue during the winter months.
Financial services and other revenue decreased in 2003, primarily due to a decrease in income associated with a maturing lease
portfolio, which produces lower revenue at Edison Capital and no nonutility real estate sales in 2003 as compared to 2002 for another
subsidiary.
Operating Expenses
Fuel expense increased in 2003 primarily due to increased generation from EME's Illinois plants and the Homer City facilities.
Purchased-power expense increased significantly in 2003 primarily due to higher expenses related to power purchased by SCE from
qualifying facilities (QFs), as discussed below.
Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated prices. Energy payments
for gas-fired QFs are generally tied to spot natural gas prices. Effective May 2002, energy payments for most renewable QFs were
based on a fixed price of 5.37(cent)per kWh, compared with an average of 2.87(cent)per kWh during the first quarter of 2002. During 2003,
spot natural gas prices were higher compared to the same period in 2002. The increase in 2003 purchased-
Page 20
power expense related to bilateral contracts and interutility contracts was also due to the increase in natural gas prices, as well
as an increase in the number of bilateral contracts entered into during 2003.
Provisions for regulatory adjustment clauses - net decreased in 2003 primarily due to a decrease in overcollections used to recover
the PROACT balance resulting from higher QF costs and an allocation adjustment for CDWR energy purchases.
Other operation and maintenance expense increased in 2003 primarily at SCE due to the San Onofre Unit 3 planned refueling outage,
higher health-care costs, higher storm-damage expenses, higher spending on certain CPUC-authorized programs, and a nuclear insurance
refund in 2002 with no comparable refund received yet in 2003.
Depreciation, decommissioning and amortization expense increased in 2003, mainly due to an increase in depreciation expense
associated with SCE's additions to transmission and distribution assets and an increase in SCE's nuclear decommissioning expense. In
addition, EME's depreciation and amortization expense increased due to higher amortization expense at Contact Energy as well as EME's
August 2002 exercise of its option to purchase the Illinois peaker power units that were subject to a lease with a third party.
Other Income and Deductions
Interest and dividend income decreased in 2003 mainly due to lower interest income from a lower PROACT balance and lower average cash
balances and lower interest rates at SCE.
Equity in income from partnerships and unconsolidated subsidiaries - net increased in 2003 primarily due to an increase in EME's
share of income from the Kern River, Midway-Sunset, Sycamore and Watson (Big 4) projects and Four Star Oil & Gas. EME's third
quarter equity income from its domestic energy projects is materially higher than equity income related to other quarters of the year
due to warmer weather during the summer months and because a number of EME's domestic energy projects, located on the west coast,
have power sales contracts that provide for higher payments during the summer months.
Other nonoperating income increased in 2003 mainly due to SCE's accrual of 2002 PBR revenue under the PBR sharing mechanism filed
with the CPUC during first quarter 2003.
Interest expense - net of amounts capitalized decreased in 2003, mainly due to lower interest expense at SCE related to the
suspension of payments for purchased power during 2001 and early 2002. These obligations were paid in March 2002. In addition,
interest expense - net of amounts capitalized decreased due to lower interest expense resulting from lower short-term and long-term
debt balances and lower interest rates on long-term debt at SCE.
Other nonoperating deductions increased in 2003 mainly due to accruals for regulatory matters at SCE.
Income Taxes
Income taxes increased in 2003 primarily due to a favorable resolution of tax audits in the first quarter of 2002.
Edison International's composite federal and state statutory rate was approximately 40.5% for both periods presented. The lower
effective tax rate of 33% realized in the first quarter of 2003 was primarily due to benefits received from low-income housing and
production credits at Edison Capital and the effect of lower foreign tax rates at EME, partially offset by property related
flow-through taxes at SCE.
Page 21
Loss from Discontinued Operations
Edison International's 2002 discontinued operations reflect earnings of $5 million from EME's Lakeland project in the United
Kingdom. On April 22, 2003, a third party announced that it had entered an agreement with Lakeland's administrative receiver to
purchase the power plant for(pound)24 million ($38 million translated at March 31, 2003 spot rate), which subject to closing conditions,
could be completed in the second quarter of 2003.
Cumulative Effect of Accounting Change-- Net
Edison International's results include a $9 million charge at EME for the cumulative effect of an accounting change related to the
new accounting standard for recording asset retirement obligations adopted by Edison International in January 2003. As SCE follows
accounting principles for rate-regulated enterprises, implementation of this new standard did not affect its earnings.
FINANCIAL CONDITION
The liquidity of Edison International is affected primarily by debt maturities, access to capital markets, dividend payments, capital
expenditures, lease obligations, asset purchases and sales, investments in partnerships and unconsolidated subsidiaries, utility
regulation and energy market conditions. Capital resources primarily consist of cash from operations, asset sales and external
financings. California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates.
A summary of current liquidity issues is provided below. A detailed discussion of liquidity issues is included in the "Financial
Condition" section in the year-ended 2002 MD&A.
Cash Flows from Operating Activities
Net cash provided (used) by operating activities:
In millions Three Months Ended March 31, 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Continuing operations $ 697 $ (929)
Discontinued operations (17) (1)
- ------------------------------------------------------------------------------------------------------------------------------
$ 680 $ (930)
- ------------------------------------------------------------------------------------------------------------------------------
The change in cash provided by operating activities from continuing operations was mainly due to SCE's March 2002 repayment of
past-due obligations, partially offset by higher overcollections used to recover regulatory assets and lower distributions from EME's
unconsolidated energy projects. Distributions from EME's unconsolidated affiliates during the first quarter of 2002 were higher than
the first quarter of 2003 primarily due to the collection of past due accounts receivable from California utilities, arising from the
California energy crisis, by EME's investments in California QFs, which amounts were then distributed to their partners. The change
was also due to timing of cash receipts and disbursements related to working capital items at both SCE and EME.
Cash Flows from Financing Activities
Net cash used by financing activities:
In millions Three Months Ended March 31, 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Continuing operations $ (191) $ (1,002)
Discontinued operations -- (4)
- ------------------------------------------------------------------------------------------------------------------------------
$ (191) $ (1,006)
- ------------------------------------------------------------------------------------------------------------------------------
Page 22
Cash used by financing activities from continuing operations in 2002 mainly consisted of long-term and short-term debt payments at
SCE and EME.
During the first quarter of 2003, Edison International (parent only) repurchased approximately $132 million of the outstanding $750
million of its 6-7/8% notes due September 2004. SCE repaid $300 million of a one-year term loan due March 3, 2003, which was part of
the $1.6 billion financing that took place in the first quarter of 2002. EME's financing activity in the first quarter of 2003
consisted of net borrowings of $80 million on EME's $487 million corporate credit facility, $320 million in borrowings by Contact
Energy, EME's 51% owned subsidiary, of which $275 million was used to finance Contact Energy's acquisition of the Taranaki Combined
Cycle power station (see "Acquisitions and Dispositions" for further discussion of the acquisition), and debt service payments of $23
million.
During the first quarter of 2002, SCE repaid $531 million of commercial paper, $400 million of its maturing principal on its senior
unsecured notes, and remarketed $196 million of the $550 million of pollution-control bonds repurchased during December 2000 and
early 2001. Also during the first quarter of 2002, SCE replaced the $1.65 billion credit facility with a $1.6 billion financing and
made a payment of $50 million to retire the remainder of the credit facility. The $1.6 billion financing included a $600 million,
one-year term loan due March 3, 2003 (see additional discussion in "SCE's Liquidity Issues"). EME's financing activity in the first
quarter of 2002 consisted of net payments of $80 million on EME's corporate credit facility, debt service payments of $22 million and
$84 million in borrowings under a note purchase agreement entered into in January 2002. Edison Capital financing activity in the
first quarter of 2002 included a $94 million pay off of debt.
Cash Flows from Investing Activities
Net cash provided used by investing activities:
In millions Three Months Ended March 31, 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Continuing operations $ (635) $ (234)
Discontinued operations 4 1
- ------------------------------------------------------------------------------------------------------------------------------
$ (631) $ (233)
- ------------------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities are affected by additions to property and plant, EME's sales of assets and SCE's funding of
nuclear decommissioning trusts.
First quarter 2003 additions to SCE's property and plant were approximately $267 million, primarily for transmission and distribution
assets. EME's capital additions in the first quarter of 2003 were $56 million primarily for new plant and equipment related to EME's
Illinois plants and the Homer City facilities. EME's first quarter 2003 investing activity also included $275 million paid by
Contact Energy for the acquisition of Taranaki Combined Cycle power station (see "Acquisitions and Dispositions" for further
discussion of the acquisition), and $23 million in equity contribution to EME's Sunrise and CBK projects.
First quarter 2002 additions to SCE's property and plant were approximately $229, primarily for transmission and distribution
assets. EME's capital additions in the first quarter of 2002 were $72 million primarily for new plant and equipment related to EME's
Valley Power Peaker project in Australia, Illinois plants, and the Homer City facilities. EME's first quarter 2002 investing
activity also included an $80 million payment for the purchase of a power sales agreement, $147 million in payments for three
turbines and termination of its Master Turbine Lease, $44 million in proceeds from EME's sale of its ownership interests in three
energy projects, and $79 million in distributions from EME's projects.
Page 23
Edison International's (parent only) Liquidity Issues
The parent company's liquidity and its ability to pay interest, debt principal, operating expenses and dividends to common
shareholders are affected by dividends from subsidiaries, tax-allocation payments under its tax allocation agreement with its
subsidiaries, and capital raising activities.
The CPUC regulates SCE's capital structure by requiring that SCE maintain a prescribed percentage of common equity, preferred stock
and long-term debt in the utility's capital structure. SCE may not make any distributions to Edison International that would reduce
the common equity component of SCE's capital structure below the prescribed level. SCE's settlement agreement with the CPUC also
precludes SCE from declaring or paying dividends or other distributions on its common stock (all of which is held by its parent,
Edison International) prior to the earlier of the date on which SCE has recovered all of its procurement-related obligations or
January 1, 2005, except that if SCE has not recovered all of its procurement-related obligations by December 31, 2003, SCE may apply
to the CPUC for consent to resume common stock dividends prior to January 1, 2005 and the CPUC will not unreasonably withhold its
consent. Material factors affecting the timing of recovery of the PROACT balance are discussed in the "SCE's Regulatory Matters"
section in the year-ended 2002 MD&A. In addition, see "--SCE's Liquidity Issues" for further discussion of factors affecting the
ability of SCE to make dividend payments.
Edison Capital's ability to make dividend payments is restricted by debt covenants, which require Edison Capital to maintain a
specified minimum net worth. Edison Capital currently exceeds the threshold amount.
Currently, MEHC is permitted to pay dividends under the terms of its outstanding debt (a) in amounts sufficient to permit Edison
International to make required interest payments on its outstanding 6-7/8% notes due 2004, (b) to pay Edison International corporate
overhead in amounts consistent with historically expended amounts, and (c) for other Edison International working capital and general
corporate purposes in an amount not to exceed $50 million. After July 15, 2003, MEHC may not pay dividends unless it has an interest
coverage ratio of 2.0x. At March 31, 2003, its interest coverage ratio was 1.49x. See "--MEHC's Liquidity Issues--MEHC's Interest
Coverage Ratio." MEHC did not declare or pay a dividend in the first quarter of 2003. MEHC's ability to pay dividends is dependent
on EME's ability to pay dividends to MEHC.
EME and its subsidiaries have certain dividend restrictions as discussed in "--EME's Liquidity Issues" section below. EME did not pay
or declare a dividend during first quarter 2003.
During the first quarter of 2003, Edison International repurchased approximately $132 million of the outstanding $750 million of its
6-7/8% notes due September 2004. The ability of Edison International to pay its 6-7/8% notes due September 2004 may be substantially
dependent, among other things, on subsidiary dividends.
Edison Mission Midwest Holdings, a subsidiary of EME has $911 million of debt maturing in December 2003, which will need to be
repaid, extended or refinanced. There is no assurance that EME will be able to repay, extend or refinance the Edison Mission Midwest
Holdings debt obligation on similar terms and rates as the existing debt, on commercially reasonable terms, on the terms permitted
under the MEHC financing documents or at all. The independent accountants' audit opinions on the year-end 2002 financial statements
of MEHC, EME and Midwest Generation contain an explanatory paragraph that indicates the consolidated financial statements have been
prepared on the basis that these companies will continue as going concerns and that the uncertainty about Edison Mission Midwest
Holdings' ability to repay, extend, or refinance this obligation raises substantial doubt about their ability to continue as going
concerns. Edison International's investment in MEHC, through a wholly owned subsidiary, as of
Page 24
March 31, 2003, was $929 million. MEHC's investment in EME, as of March 31, 2003, was $1.9 billion.
Since May 2001, Edison International has deferred the interest payments in accordance with the terms of its outstanding $825 million
quarterly income debt securities, due 2029, issued to an affiliate. This caused a corresponding deferral of distributions on
quarterly income preferred securities issued by that affiliate. Interest payments may be deferred for up to 20 consecutive
quarters. Edison International cannot pay cash dividends on or purchase its common stock as long as interest is being deferred.
At March 31, 2003, the parent company had approximately $91 million of cash and equivalents on hand.
SCE's Liquidity Issues
SCE expects to meet its continuing obligations in 2003 from cash and equivalents on hand and operating cash flows. SCE had $1.1
billion in cash and equivalents as of March 31, 2003.
In January 2002, the CPUC adopted a resolution implementing a settlement agreement with SCE. Based on the rights to recover its past
procurement-related costs, SCE repaid its undisputed past-due obligations and near-term debt maturities in March 2002, using cash on
hand resulting and the proceeds of $1.6 billion credit facilities and the remarketing of $196 million in pollution-control bonds.
The $1.6 billion credit facilities included a $600 million, one-year term loan due on March 3, 2003. SCE prepaid $300 million of
this loan on August 14, 2002 and the remaining $300 million on February 11, 2003. The $1.6 billion credit facilities also included a
$300 million revolving line of credit, which, at March 31, 2003 was fully drawn and expired March 2004, and a $700 million term loan
with a March 2005 final maturity. On April 16, 2003, SCE paid off the full amount of its revolving line of credit. Under the term
loan, net cash proceeds for the issuance of capital stock or new indebtedness must be used to reduce the term loan subject to certain
exceptions.
On February 24, 2003, SCE completed an exchange offer for its 8.95% variable rate notes due November 2003. A total of $966 million
of these notes were exchanged for $966 million of a new series of first and refunding mortgage bonds due February 2007. As a result
of the exchange offer, SCE's remaining significant debt maturities in 2003 are approximately $159 million, comprising $34 million of
the 8.95% variable rate notes due November 2003 that were not exchanged and $125 million in first and refunding mortgage bonds due
June 2003. In addition, approximately $246 million of rate reduction notes are due throughout 2003. These notes have a separate
cost recovery mechanism approved by state legislation and CPUC decisions.
Currently, SCE expects to recover the PROACT balance during the summer of 2003. Material factors affecting the timing of recovery of
the PROACT balance are discussed in the "SCE's Regulatory Matters" section in the year-ended 2002 MD&A.
As of March 31, 2003, SCE's common equity to total capitalization ratio, for rate-making purposes, was approximately 62%. This is
substantially greater than the CPUC-authorized level of 48%. SCE's settlement agreement with the CPUC provides that the CPUC will
not impose any penalty on SCE for noncompliance with the authorized capital structure during the PROACT recovery period. SCE expects
to rebalance its capital structure to CPUC-authorized levels in the future by paying dividends to its parent, Edison International,
and issuing debt as necessary. Factors that affect the amount and timing of such actions include, but are not limited to, the
outcome of the pending appeal of the stipulated judgment approving SCE's settlement agreement with the CPUC (See "SCE's Regulatory
Matters--CPUC Litigation Settlement Agreement"), SCE's access to the capital markets, and actions by the CPUC.
Page 25
SCE resumed procurement of its residual net short (the amount of energy needed to serve SCE's customers from sources other than its
own generating plants, power purchase contracts and CDWR contracts) on January 1, 2003 and as of April 30, 2003, posted $98 million
in collateral to secure its obligations under power purchase contracts and to transact through the Independent System Operator (ISO)
for imbalance power.
SCE's liquidity may be affected by, among other things, matters described in "SCE's Regulatory Matters--CPUC Litigation Settlement
Agreement,--CDWR Revenue Requirement Proceeding, and--Generation Procurement Proceedings" sections.
MEHC's Liquidity Issues
At March 31, 2003, MEHC and its subsidiaries had cash and cash equivalents of $739 million and EME had available a total of $274
million of borrowing capacity under its $487 million corporate credit facility. MEHC's consolidated debt at March 31, 2003, was $7.6
billion, including $911 million of debt maturing in December 2003, which is owed by EME's largest subsidiary, Edison Mission Midwest
Holdings. In addition, EME's subsidiaries have $7 billion of long-term lease obligations that are due over a period ranging up to 32
years.
The $911 million of debt of Edison Mission Midwest Holdings maturing in December 2003 will need to be repaid, extended or refinanced.
Edison Mission Midwest Holdings is not expected to have sufficient cash to repay the $911 million debt due in December 2003, and
there is no assurance that it will be able to extend or refinance its debt obligation on similar terms and rates as the existing
debt, on commercially reasonable terms, on the terms permitted under the financing documents entered into by MEHC in July 2001, or at
all. MEHC's independent accountants' audit opinion for the year ended December 31, 2002 contains an explanatory paragraph that
indicates the consolidated financial statements have been prepared on the basis that MEHC will continue as a going concern and that
the uncertainty about Edison Mission Midwest Holdings' ability to repay, extend or refinance this obligation raises substantial doubt
about MEHC's ability to continue as a going concern. Accordingly, the consolidated financial statements do not include any
adjustments that might result from the resolution of this uncertainty.
The remainder of this section discusses MEHC's liquidity issues on a stand alone basis. See "--EME's Liquidity Issues" for further
discussion of EME related items that may impact MEHC on a consolidated basis.
MEHC's ability to honor its obligations under the senior secured notes and the term loan after the two year interest reserve period
(which expires July 2, 2003 for the term loan and July 15, 2003 for the senior secured notes) and to pay overhead is substantially
dependent upon the receipt of dividends from EME and receipt of tax-allocation payments from MEHC's parent, a wholly owned subsidiary
of Edison International and ultimately Edison International. Part of the proceeds from the senior secured notes and the term loan
were used to fund escrow accounts to secure the first four interest payments due under the senior secured notes and the interest
payments for the first two years under the term loan. Other than the dividends received from EME, funds received pursuant to MEHC's
tax-allocation arrangements (see--"MEHC's Intercompany Tax-Allocation Payments") with MEHC's affiliates and the interest reserve
account, MEHC will not have any other source of funds to meet its obligations under the senior secured notes and the term loan.
Dividends from EME may be limited based on its earnings and cash flow, terms of restrictions contained in EME's contractual
obligations (including its corporate credit facility), EME's charter documents, business and tax considerations, and restrictions
imposed by applicable law. MEHC did not receive any distributions from EME during the first quarter of 2003.
At March 31, 2003, MEHC had cash and cash equivalents of $85 million and restricted cash of $88 million (excluding amounts held by
EME and its subsidiaries). Restricted cash represents monies
Page 26
deposited into the interest escrow accounts described above. The funds collected in the accounts will be used to make the interest
payments due under the senior secured notes and the term loan through July 15, 2003. The timing and amount of distributions from EME
and its subsidiaries may be affected by many factors beyond MEHC's control.
If MEHC is unable to make any payment on the senior secured notes or under the term loan as that payment becomes due, it would result
in a default under the senior secured notes and the term loan and could lead to foreclosure on MEHC's ownership interest in the
capital stock of EME.
Description of Term Loan Put-Option
The term loan bears interest at a floating rate equal to the three-month London interbank offered rate (LIBOR) plus 7.50% and matures
on July 2, 2006. In July 2004, on the third anniversary of the term loan, the lenders under the term loan may require that MEHC
repay up to $100 million of the principal amount at par.
MEHC's Interest Coverage Ratio
The following details of MEHC's interest coverage ratio are provided as an aid to understanding the components of the computations
that are set forth in the indenture governing MEHC's senior secured notes. This information is not intended to measure the financial
performance of MEHC and, accordingly, should not be used in lieu of the financial information set forth in MEHC's consolidated
financial statements. The terms Funds Flow from Operations, Operating Cash Flow and Interest Expense are as defined in the indenture
and are not the same as would be determined in accordance with generally accepted accounting principles.
MEHC's interest coverage ratio is comprised of interest income and expense related to its holding company activities and the
consolidated financial information of EME. For a complete discussion of EME's interest coverage ratio and the components included
therein, see "--EME's Liquidity Issues--EME's Interest Coverage Ratio" below. The following table sets forth MEHC's interest coverage
ratio for the twelve months ended March 31, 2003 and the year ended December 31, 2002:
March 31, December 31,
In millions 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Funds Flow From Operations:
EME $ 652 $ 692
Less: Operating cash flow from
unrestricted subsidiaries -- (17)
Add: Outflows of funds from
operations of projects sold 1 2
MEHC 5 7
- ------------------------------------------------------------------------------------------------------------------------------
$ 658 $ 684
- ------------------------------------------------------------------------------------------------------------------------------
Interest Expense:
EME $ 281 $ 293
EME - affiliate debt 2 2
MEHC interest expense 160 159
- ------------------------------------------------------------------------------------------------------------------------------
Total interest expense $ 443 $ 454
- ------------------------------------------------------------------------------------------------------------------------------
Interest Coverage Ratio 1.49 1.51
- ------------------------------------------------------------------------------------------------------------------------------
The above interest coverage ratio was determined in accordance with the definitions set forth in the bond indenture governing MEHC's
senior secured notes and the credit agreement governing the term loan.
Page 27
The interest coverage ratio prohibits MEHC, EME and its subsidiaries from incurring additional indebtedness, except as specified in
the indenture and the financing documents, unless MEHC's interest coverage ratio exceeds 1.75 to 1 for the immediately preceding four
fiscal quarters prior to June 30, 2003 and 2.0 to 1 for periods thereafter.
MEHC's Intercompany Tax-Allocation Payments
MEHC is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to
participate in tax-allocation payments with other subsidiaries of Edison International. These arrangements depend on Edison
International continuing to own, directly or indirectly, at least 80% of the voting power of the stock of MEHC and at least 80% of the
value of such stock. The arrangements are subject to the terms of tax allocation and payment agreements among Edison International,
MEHC, EME and other Edison International subsidiaries. The agreements to which MEHC is a party may be terminated by the immediate
parent company of MEHC at any time, by notice given before the first day of the year with respect to which the termination is to be
effective. However, termination does not relieve any party of any obligations with respect to any tax year beginning prior to the
notice. MEHC became a party to the tax-allocation agreement with a wholly owned subsidiary of Edison International on July 2, 2001,
when it became part of the Edison International consolidated filing group. MEHC has historically received tax-allocation payments
related to domestic net operating losses incurred by MEHC. The right of MEHC to receive and the amount and timing of tax-allocation
payments are dependent on the inclusion of MEHC in the consolidated income tax returns of Edison International and its subsidiaries,
the amount of net operating losses and other tax items of MEHC, its subsidiaries, and other subsidiaries of Edison International and
specific procedures regarding allocation of state taxes. MEHC receives tax-allocation payments for tax losses when and to the extent
that the consolidated Edison International group generates sufficient taxable income in order to be able to utilize MEHC's tax losses
in the consolidated income tax returns for Edison International and its subsidiaries. During the first quarter of 2003, MEHC paid
$286,000 in tax-allocation payments to Edison International. In the future, based on the application of the factors cited above,
MEHC may be obligated during periods they generate taxable income to make payments under the tax-allocation agreements.
EME's Liquidity Issues
The discussions below include the following matters that affect EME's liquidity: EME's credit ratings, EME's corporate liquidity,
historical distributions received by EME, the ability of EME to pay dividends, EME's interest coverage and recourse debt to recourse
capital ratios, EME subsidiary financing plans, and EME's intercompany tax-allocation payments.
EME's Credit Ratings
Credit ratings for EME and its subsidiaries, Edison Mission Midwest Holdings and Edison Mission Marketing & Trading, are as follows:
Moody's
Rating S&P Rating
- ------------------------------------------------------------------------------------------------------------------------------
EME (senior unsecured) Ba3 BB-
Edison Mission Midwest Holdings (bank facility) Ba2 BB-
Edison Mission Marketing & Trading (senior unsecured) Not Rated BB-
- ------------------------------------------------------------------------------------------------------------------------------
Standard & Poor's has assigned a negative rating outlook for each of these entities. Moody's has EME's and Edison Mission Midwest
Holdings' ratings under review for further downgrade.
Page 28
The credit ratings of EME are below investment grade and, accordingly, EME has agreed to provide collateral in the form of cash and
letters of credit for the benefit of counterparties for its price risk management and domestic trading activities related to accounts
payable and unrealized losses ($65 million as of May 9, 2003). EME has also provided collateral for a portion of its United Kingdom
trading activities. To this end, EME's subsidiary, Edison Mission Operation and Maintenance Limited, has obtained a cash
collateralized credit facility, under which letters of credit totaling $27 million have been issued as of April 30, 2003.
EME anticipates that sales of power from its Illinois plants, Homer City facilities and First Hydro plants in the United Kingdom may
require additional credit support, depending upon market conditions and the strategies adopted for the sale of this power. Changes
in forward market prices and margining requirements could further increase the need for credit support for the price risk management
and trading activities related to these projects. EME currently projects the potential working capital to support its price risk
management and trading activity to be between $100 million and $200 million from time to time during 2003.
EME 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 again. EME notes that these credit ratings are not
recommendations to buy, sell or hold its securities and may be revised or withdrawn at any time by a rating agency.
Credit Rating of Edison Mission Midwest Holdings
As a result of the downgrade of Edison Mission Midwest Holdings below investment grade in October 2002, provisions in the agreements
binding on Edison Mission Midwest Holdings and Midwest Generation restrict the ability of Edison Mission Midwest Holdings to make
distributions to its parent company, thereby eliminating distributions to EME.
The following table summarizes the provisions restricting cash distributions (sometimes referred to as cash traps) and the related
changes in the cost of borrowing by Edison Mission Midwest Holdings under the applicable financing agreements. The currently
applicable provisions are those set forth in the same row as the Standard & Poor's rating "BB-."
Cost of Borrowing
S&P Rating Moody's Rating Margin (basis points) Cash Trap
- -----------------------------------------------------------------------------------------------------------------------------------
(based on LIBOR)
BBB- or higher Baa3 or higher 150 No cash trap
BB+ Ba1 225 50% of excess cash flow trapped until six month debt
service reserve is funded
BB Ba2 275 100% of excess cash flow trapped
BB- Ba3 325 100% of excess cash flow trapped
B+ B1 325 100% of excess cash flow trapped and used to repay debt
- -----------------------------------------------------------------------------------------------------------------------------------
Based on its current credit rating, provisions in the agreements binding on Edison Mission Midwest Holdings require it to deposit, on
a quarterly basis, 100% of its excess cash flow as defined in the agreements into a cash flow recapture account held and maintained
by the collateral agent. In accordance with these provisions, Edison Mission Midwest Holdings deposited $50 million into the cash
flow recapture account on October 31, 2002 and another $28 million on January 27, 2003. The funds in the cash flow recapture account
may be used only to meet debt service obligations of Edison Mission Midwest Holdings if funds are not otherwise available from
working capital. There is no assurance that Edison Mission Midwest Holdings' current credit rating will not be lowered again, in
which case Edison
Page 29
Mission Midwest Holdings would be required to use its defined excess cash flow, as well as cash in the cash flow recapture account,
to repay indebtedness.
As part of the sale-leaseback of the Powerton and Joliet power stations, Midwest Generation loaned the proceeds ($1.4 billion) to EME
in exchange for promissory notes in the same aggregate amount. Debt service payments by EME on the promissory notes may be used by
Midwest Generation to meet its payment obligations under these leases in whole or part. Furthermore, EME has guaranteed the lease
obligations of Midwest Generation under these leases. EME's obligations under the promissory notes payable to Midwest Generation are
general corporate obligations of EME and are not contingent upon receiving distributions from Edison Mission Midwest Holdings. See
"--Historical Distributions Received by EME--Restricted Assets of EME's Subsidiaries--Edison Mission Midwest Holdings (Illinois Plants)"
for a discussion of implications for the Powerton and Joliet leases.
Credit Rating of Edison Mission Marketing & Trading
Pursuant to the Homer City sale-leaseback documents, a below investment grade credit rating of Edison Mission Marketing & Trading
restricts the ability of EME Homer City Generation L.P. (EME Homer City) to enter into permitted trading activities, as defined in
the documents, with Edison Mission Marketing & Trading to sell forward the output of the Homer City facilities. 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 of the output from the Homer City facilities through Edison Mission Marketing &
Trading, 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 Edison Mission Marketing & Trading; or (2) Edison
Mission Marketing & Trading 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, 2004. EME is permitted to sell the output of the Homer City facilities into the
Pennsylvania-New Jersey--Maryland Power Pool (PJM) at any time on a spot-market basis. See "--Market Risk Exposures--EME's Market
Risks--Commodity Price Risk--Homer City Facilities."
EME Corporate Liquidity
EME has a $487 million corporate credit facility, which includes a $275 million component, Tranche A, that expires on September 16,
2003 and a $212 million component, Tranche B, that expires on September 17, 2004. At March 31, 2003, EME had borrowing capacity
under this facility of $274 million and corporate cash and cash equivalents of $31 million.
Cash distributions from EME's subsidiaries and partnership investments, tax-allocation payments from Edison International and unused
capacity under its corporate credit facilities represent EME's major sources of liquidity to meet its cash requirements. In
addition, EME expects to complete the Sunrise project financing during the summer of 2003, which, upon completion, will result in the
receipt by EME of approximately $140 million to $150 million of capital previously invested in this project. See "--EME Subsidiary
Financing Plans." EME expects its 2003 cash requirements to be primarily composed of:
o interest payments on its indebtedness, including interest payments to Midwest Generation related to intercompany loans,
o collateral requirements in the form of letters of credit or cash margining in support of forward contracts for the sale of
power from its merchant energy operations,
Page 30
o general administrative expenses, and
o equity contribution obligations.
The timing and amount of distributions from EME's subsidiaries may be affected by many factors beyond its control. See "--Historical
Distributions Received by EME--Restricted Assets of EME's Subsidiaries." In addition, the right of EME to receive tax-allocation
payments, and the timing and amount of tax-allocation payments received by EME are subject to factors beyond EME's control. See
"--EME's Intercompany Tax-Allocation Payments." If Tranche A of the corporate facility is not extended and the Sunrise project
financing is not completed as scheduled, EME's ability to provide credit support for bilateral contracts for power and fuel of its
merchant energy operations will be severely limited. If EME is unable to provide such credit support, this will reduce the number of
counterparties willing to enter into bilateral contracts with EME's subsidiaries, thus requiring EME's subsidiaries to rely on
short-term markets instead of bilateral contracts. Furthermore, if this situation occurs, EME may not be able to meet margining
requirements if forward prices for power increase significantly. Failure to meet a margining requirement would permit the
counterparty to terminate the related bilateral contract early and demand immediate payment for the replacement value of the contract.
EME's corporate credit facility provides credit available in the form of cash advances or letters of credit. At March 31, 2003,
Tranche A consisted of borrowings of $80 million, and $132 million of letters of credit were outstanding under Tranche B. In
addition to the interest payments, EME pays a facility fee determined by its long-term credit ratings (0.875% and 1.00% at March 31,
2003 for Tranche A and Tranche B, respectively) on the entire credit facility independent of the level of borrowings.
Under the credit agreement governing its credit facility, EME has agreed to maintain an interest coverage ratio that is based on cash
received by EME, including tax-allocation payments, cash disbursements and interest paid. At March 31, 2003, EME met this interest
coverage ratio. The interest coverage ratio in the ring-fencing provisions of EME's certificate of incorporation and bylaws remains
relevant for determining EME's ability to make distributions. See "--EME's Interest Coverage Ratio."
Historical Distributions Received by EME
The following table is presented as an aid in understanding the cash flow of EME and its various subsidiary holding companies, which
depend on distributions from subsidiaries and affiliates to fund general and administrative costs and interest costs of recourse
debt. Distributions for the first three months of each year are not necessarily indicative of annual distributions due to the
seasonal fluctuations in EME's business.
In millions Quarter ended March 31, 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
Distributions from Consolidated Operating Projects:
EME Homer City Generation L.P. (Homer City facilities) $ 21 $ --
Holding companies of other consolidated operating projects 36 4
Distributions from Non-Consolidated Operating Projects:
Edison Mission Energy Funding Corp. (Big 4 projects)(1) 20 82
Four Star Oil & Gas Company -- 4
Holding companies of other non-consolidated operating projects 23 24
- -----------------------------------------------------------------------------------------------------------------------------------
Total Distributions $ 100 $ 114
- -----------------------------------------------------------------------------------------------------------------------------------
(1) Distributions do not include either capital contributions made during the California energy crisis or the subsequent
return of such capital. Distributions reflect the amount received by EME after debt service payments by Edison Mission
Energy Funding Corp.
Page 31
Total distributions to EME decreased due to:
o lower distributions from the Big 4 projects (in March 2002, SCE paid the Big 4 projects their past due accounts receivable
that accrued during the California energy crisis);
Partially offset by:
o distribution from Homer City (the project did not make a distribution in the first quarter of 2002 because it distributed
its excess cash in December 2001 upon closing the Homer City sale-leaseback transaction);
o increased shareholder dividends from Contact Energy; and
o distribution from the Loy Yang B project following completion of the refinancing of the Valley Power Peaker project
construction loan.
Restricted Assets of EME's Subsidiaries
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. Set forth below is a description of 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.
Edison Mission Midwest Holdings Co. (Illinois Plants)
Edison Mission Midwest Holdings Co. is the borrower under a $1.9 billion credit facility with a group of commercial banks. The funds
borrowed under this facility were used to fund the acquisition of the Illinois plants and provide working capital to such
operations. Midwest Generation, a wholly owned subsidiary of Edison Mission Midwest Holdings, owns or leases and operates the
Illinois plants. Midwest Generation entered into sale-leaseback transactions for the Collins Station as part of the original
acquisition and for the Powerton Station and the Joliet Station in August 2000. In order for Edison Mission Midwest Holdings to make
a distribution, Edison Mission Midwest Holdings and Midwest Generation must be in compliance with the covenants specified in these
agreements, including maintaining a minimum credit rating. Because Edison Mission Midwest Holdings' credit rating is below investment
grade, no distributions can currently be made by Edison Mission Midwest Holdings to its parent company and ultimately, to EME at this
time. See "--EME's Credit Ratings--Credit Rating of Edison Mission Midwest Holdings."
Edison Mission Midwest Holdings must also maintain a debt service coverage ratio for the prior twelve-month period of at least 1.50
to 1 as long as the power purchase agreements with Exelon Generation represent 50% or more of Edison Mission Midwest Holdings' and
its subsidiaries' revenue. If the power purchase agreements with Exelon Generation represent less than 50% of Edison Mission Midwest
Holdings' and its subsidiaries' revenue, it must maintain a debt service coverage ratio of at least 1.75 to 1. EME expects that
revenue for 2003 from Exelon Generation will represent 50% or more of Edison Mission Midwest Holdings' and its subsidiaries'
revenue. In addition, Edison Mission Midwest Holdings must maintain a debt-to-capital ratio no greater than 0.60 to 1. Failure to
meet the historical debt service coverage ratio and the debt-to-capital ratio are events of default under the credit agreement and
Collins lease agreements, which, upon a vote by a majority of the lenders, could cause an acceleration of the due date of the
obligations of Edison Mission Midwest Holdings and those associated with the Collins lease. Such an acceleration would result in an
event of default under the Powerton and
Page 32
Joliet leases. During the 12 months ended March 31, 2003, the historical debt service coverage ratio was 3.77 to 1 and the
debt-to-capital ratio was 0.52 to 1.
There are no restrictions on the ability of Midwest Generation to make payments on the outstanding intercompany loans from its
affiliate Edison Mission Overseas Co. (which is also a subsidiary of Edison Mission Midwest Holdings) or to make distributions
directly to Edison Mission Midwest Holdings.
EME Homer City Generation L.P. (Homer City facilities)
EME Homer City Generation L.P. completed a sale-leaseback of the Homer City facilities in December 2001. In order to make a
distribution, EME Homer City must be in compliance with the covenants specified in the lease agreements, including the following
financial performance requirement measured on the date of distribution:
o At the end of each quarter, the senior rent service coverage ratio for the prior twelve-month period (taken as a whole) must
be greater than 1.7 to 1. The senior rent service coverage ratio is defined as all income and receipts of EME Homer City less
amounts paid for operating expenses, required capital expenditures, taxes and financing fees divided by the aggregate amount of
the debt portion of the rent, plus fees, expenses and indemnities due and payable with respect to the lessor's debt service
reserve letter of credit.
At the end of each quarter, the equity and debt portions of rent then due and payable must have been paid. The senior rent service
coverage ratio (discussed in the bullet point above) projected for each of the prospective two twelve-month periods must be greater
than 1.7 to 1. No more than two rent default events may have occurred, whether or not cured. A rent default event is defined as the
failure to pay the equity portion of the rent within five business days of when it is due.
During the 12 months ended March 31, 2003, the senior rent service coverage ratio was 4.2 to 1.
First Hydro Holdings
A subsidiary of First Hydro Holdings, First Hydro Finance plc, is the borrower of(pound)400 million ($632 million translated at March 31,
2003 spot rate) of Guaranteed Secured Bonds due in 2021. In order to make a distribution, First Hydro Finance must be in compliance
with the covenants specified in its bond indenture, including an interest coverage ratio. When measured for the twelve-month period
ended December 31, 2002, First Hydro Holdings met the interest coverage ratio and made a distribution of $18 million on May 7, 2003.
On March 14, 2003, First Hydro Finance plc received a letter from the trustee for the First Hydro bonds, requesting that First Hydro
Finance engage in a process to determine whether an early redemption option in favor of the bondholders has been triggered under the
terms of the First Hydro bonds. This letter states that, given requests made of the trustee by a group of First Hydro bondholders,
the trustee needs to satisfy itself whether the termination of the pool system in the United Kingdom (replaced with the new
electricity trading arrangements, referred to as NETA), was materially prejudicial to the interests of the bondholders. If this were
the case, it could provide the First Hydro bondholders with an early redemption option. In this regard, on August 29, 2000, First
Hydro Finance notified the trustee that the enactment of the Utilities Act of 2000, which laid the foundation for NETA, would result,
after its implementation, in a so called restructuring event under the terms of the First Hydro bonds. However, First Hydro Finance
did not believe then, nor does it believe now, that this event was materially prejudicial to the First Hydro bondholders. Since NETA
implementation, First Hydro Finance has continued to meet all of its debt service obligations and financial covenants under the bond
documentation, including the required interest coverage ratio. Until its receipt of the trustee's March 14, 2003 letter, First Hydro
Finance had not received a response from the trustee to its August 29, 2000
Page 33
notice. First Hydro Finance will dispute any attempt to have the early redemption option deemed applicable due to NETA
implementation.
Neither the August 2000 notice provided to the trustee, nor the March 14, 2003 letter from the trustee constitutes an event of
default under the terms of the First Hydro bonds; and there is no recourse to EME for the obligations of First Hydro Finance in
respect of the First Hydro bonds. However, if the bondholders were entitled to an early redemption option, First Hydro Finance would
be obligated to purchase all First Hydro bonds put to it by bondholders at par plus an early redemption premium. If all bondholders
opted for the early redemption option, it is unlikely that First Hydro Finance would have sufficient financial resources to so
purchase the bonds. There is no assurance that First Hydro Finance would be able to obtain additional financing to fund the purchase
of the First Hydro bonds. Therefore, an exercise of the early redemption option by the bondholders could lead to administration
proceedings as to First Hydro Finance in the United Kingdom, which is similar to Chapter 11 bankruptcy proceedings in the United
States. If these events were to occur, it would have a material adverse effect upon First Hydro Finance and could have a material
adverse effect upon EME.
Edison Mission Energy Funding Corp. (Big 4 Projects)
EME's subsidiaries, which EME refers to, in this context, as the guarantors, that hold EME's interests in the Big 4 projects
completed a $450 million secured financing in December 1996. Edison Mission Energy Funding Corp., a special purpose Delaware
corporation, issued notes ($260 million) and bonds ($190 million), the net proceeds of which were lent to the guarantors in exchange
for a note. The guarantors have pledged their cash proceeds from the Big 4 projects to Edison Mission Energy Funding as collateral
for the note. All distributions receivable by the guarantors from the Big 4 projects are deposited into a trust account from which
debt service payments are made on the obligations of Edison Mission Energy Funding and from which distributions may be made to EME if
Edison Mission Energy Funding is in compliance with the terms of the covenants in its financing documents, including the following
requirements measured on the date of distribution:
o The debt service coverage ratio for the preceding four fiscal quarters is at least 1.25 to 1.
o The debt service coverage ratio projected for the succeeding four fiscal quarters is at least 1.25 to 1.
The debt service coverage ratio is determined by the amount of distributions received by the guarantors from the Big 4 projects
during the relevant quarter divided by the debt service (principal and interest) on Edison Mission Energy Funding's notes and bonds
paid or due in the relevant quarter. During the 12 months ended March 31, 2003, the debt service coverage ratio was 2.16 to 1.
Although the credit ratings of Edison Mission Energy Funding's notes and bonds are below investment grade, this has no effect on the
ability of the guarantors to make distributions to EME.
CBK Project
EME holds a 50% interest in CBK Power Co Ltd. CBK Power operates under a 25-year build-rehabilitate-operate-transfer agreement with
National Power Corporation for the 755 MW Caliraya-Botocan-Kalayaan hydro electric complex located in the Republic of the
Philippines, which EME refers to as the CBK project. On April 23, 2003, the President of the Republic of the Philippines signed into
law the 2003 General Appropriations Bill, which includes a provision that prohibits payments by agencies of the Philippine government
to CBK Power with respect to two of its units until National Power Corporation submits a report based upon a review of "overpayments"
to the CBK project, if any, and until the project documentation has been amended to provide for recovery by National Power
Corporation of any "overpayments." The assertion regarding "overpayment" stems from a supplemental agreement entered into during
1999, which modified the original build-rehabilitate-operate-transfer agreement by adjusting the schedule for completion of two units
of the CBK complex.
Page 34
Under the supplemental agreement, rehabilitation of existing Kalayaan Units 1 and 2 was brought forward because of National Power
Corporation's concern about the possibility of transformer failure and other risks affecting the reliability of these units. Under
the original schedule, Kalayaan Units 1 and 2 were to be operated by CBK Power for operation and maintenance fees only during the
lengthy construction of new Kalayaan Units 3 and 4, and upon completion of these units, Kalayaan Units 1 and 2 were to be taken out
of service for rehabilitation. Under the build-rehabilitate-operate-transfer agreement, National Power Corporation is obligated to
pay capacity recovery fees to CBK Power upon completion of the construction or rehabilitation of each unit. EME understands the term
"overpayment" as used in the Special Provision of the General Appropriations Act to refer to the payments of capital recovery fees
for the Kalayaan Units 1 and 2 arising from the earlier than initially scheduled rehabilitation of these units. At the time EME made
its investment in CBK Power, the decision to accelerate the work on Kalayaan Units 1 and 2 had been made and incorporated in the
supplemental agreement, and all appropriate Philippine government approvals of the supplemental and other project agreements with
National Power Corporation had been obtained. Subsequently, some parties in the Philippines have contended that payments made to CBK
Power as a result of the earlier than initially scheduled rehabilitation of Kalayaan Units 1 and 2 were unreasonable in comparison to
the amount of additional work required to rehabilitate the units.
CBK Power is currently considering legal options available to it to respond to the enactment of the Special Provision. Failure by
National Power Corporation to pay and/or a failure by the Philippine government to honor its commitments under the Government
Undertaking signed in connection with the project to cause National Power Corporation to pay will constitute defaults under the
build-rehabilitate-operate-transfer agreement and the Government Undertaking, respectively. On April 28, 2003, CBK sent a notice of
claim to the President of the Republic of the Philippines, pursuant to the terms of the Government Undertaking. A default under the
Government Undertaking will permit CBK Power to require the Philippine government to purchase the power plants subject to the
build-rehabilitate-operate-transfer agreement for a price, which will at least recover EME's investment in the project. Prior to
asserting these rights, however, CBK Power is required to engage in good faith negotiations with National Power Corporation in an
attempt to resolve the situation. These discussions have commenced but thus far have not resulted in a mutually acceptable
resolution.
CBK Power has advised its lenders of these developments and is discussing with them the ramifications under its credit agreements.
Further, CBK Power has advised its lenders that National Power Corporation is presently overdue in the payment of invoices totaling
$11 million, a substantial portion of which is related to Kalayaan Units 1 and 2. Some of these events, if not cured, are or may
with the passage of time become events of default under CBK Power's credit agreements, which would permit the lenders to demand
payment in full of the project loans and to foreclose upon the assets of CBK Power. CBK Power intends to seek a waiver from the
lenders of any existing defaults and any related defaults as may occur while it considers its response to these developments and
enters into negotiations with National Power Corporation. There is no assurance, however, that such a waiver will be obtained or
that, if not obtained, the lenders will not exercise their rights under the credit agreement.
As of March 31, 2003, EME has invested $49 million in the CBK project and as of such date is committed to invest up to an additional
$30 million. EME believes that either on a negotiated basis or through the exercise of legal remedies it shall recover its entire
investment. The indebtedness incurred by CBK Power is non-recourse to EME and, except for EME's commitment to contribute up to an
additional $30 million as equity, EME has no obligation with respect to CBK Power's indebtedness. Further, these events do not
constitute a default under any indebtedness incurred by EME or to which EME or any of its affiliates is subject.
Page 35
Ability of EME to Pay Dividends
EME's organizational documents contain restrictions on its ability to declare or pay dividends or distributions. These restrictions
require the unanimous approval of its board of directors, including at least one independent director, before it can declare or pay
dividends or distributions, unless either of the following is true:
o EME then has investment grade ratings with respect to its senior unsecured long-term debt and receives rating agency
confirmation that the dividend or distribution will not result in a downgrade; or
o such dividends and distributions do not exceed $32.5 million in any fiscal quarter and EME then meets an interest coverage
ratio of not less than 2.2 to 1 for the immediately preceding four fiscal quarters.
EME's interest coverage ratio for the twelve months ended March 31, 2003 was 2.32 to 1. See further details of EME's interest
coverage ratio below. Accordingly, EME is currently permitted to pay dividends of up to $32.5 million in the second quarter of 2003
under the "ring-fencing" provisions of EME's certificate of incorporation and bylaws. EME did not pay or declare any dividends to
MEHC during the first quarter of 2003.
EME's Interest Coverage Ratio
The following details of EME's interest coverage ratio are provided as an aid to understanding the components of the computations
that are set forth in EME's organizational documents. This information is not intended to measure the financial performance of EME
and, accordingly, should not be used in lieu of the financial information set forth in MEHC's consolidated financial statements. The
terms Funds Flow from Operations, Operating Cash Flow and Interest Expense are as defined in EME's organizational documents and are
not the same as would be determined in accordance with generally accepted accounting principles.
Page 36
The following table sets forth the major components of the interest coverage ratio for the twelve months ended March 31, 2003 and the
year ended December 31, 2002:
March 31, December 31,
In millions 2003 2002
- -----------------------------------------------------------------------------------------------------------------------------------
Funds Flow from Operations:
Operating Cash Flow(1) from Consolidated Operating Projects(2):
Illinois Plants(3) $ 304 $ 294
Homer City 95 51
First Hydro 35 45
Other consolidated operating projects 146 160
Price risk management and trading 10 16
Distributions from non-consolidated Big 4 projects 75 137
Distributions from other non-consolidated operating projects 115 120
Interest income 6 8
Operating expenses (134) (139)
- -----------------------------------------------------------------------------------------------------------------------------------
Total funds flow from operations $ 652 $ 692
- -----------------------------------------------------------------------------------------------------------------------------------
Interest Expense:
From obligations to unrelated third parties $ 167 $ 178
From notes payable to Midwest Generation 114 115
- -----------------------------------------------------------------------------------------------------------------------------------
Total interest expense $ 281 $ 293
- -----------------------------------------------------------------------------------------------------------------------------------
Interest Coverage Ratio 2.32 2.36
- -----------------------------------------------------------------------------------------------------------------------------------
(1) Operating cash flow is defined as revenue less operating expenses, foreign taxes paid and project debt service. Operating
cash flow does not include capital expenditures or the difference between cash payments under EME's long-term leases and
lease expenses recorded in EME's income statement. EME expects its cash payments under its long-term power plant leases to
be higher than its lease expense through 2014.
(2) Consolidated operating projects are entities of which EME owns more than a 50% interest and, thus, include the operating
results and cash flows in its consolidated financial statements. Non-consolidated operating projects are entities of which
EME owns 50% or less and which EME accounts for on the equity method.
(3) Distribution to EME of funds flow from operations of the Illinois plants is currently restricted. See "--EME's Credit
Ratings--Credit Rating of Edison Mission Midwest Holdings."
The major factors affecting funds flow from operations during the twelve months ended March 31, 2003, compared to the year ended
December 31, 2002, were:
o lower distributions from the Big 4 projects (in March 2002, SCE paid the Big 4 projects their past due accounts receivable
that accrued during the California energy crisis); and
o higher revenue at Homer City due to increased generation and higher energy prices.
Interest expense decreased by $12 million for the twelve months ended March 31, 2003, compared to the year ended December 31, 2002,
due to a lower average debt balance.
The above interest coverage ratio is not determined in accordance with generally accepted accounting principles as reflected in
Edison International's Consolidated Statements of Cash Flows. Accordingly, this ratio should not be considered in isolation or as a
substitute for cash flows from operating activities or cash flow statement data set forth in Edison International's Consolidated
Statement of Cash Flows. This ratio does not measure the liquidity or ability of EME's subsidiaries to meet their debt service
obligations. Furthermore, this ratio is not necessarily comparable to other similarly titled captions of other companies due to
differences in methods of calculations.
Page 37
EME's Recourse Debt to Recourse Capital Ratio
Under the credit agreement governing its credit facility, EME has agreed to maintain a recourse debt to recourse capital ratio as
shown in the table below.
Actual at
Financial Ratio Covenant March 31, 2003 Description
- -------------------------------------------------------------------------------------------------------------------------------------
Recourse Debt to Less than or 62.8% Ratio of (a) senior recourse debt to (b) sum
Recourse Capital equal to of (i) shareholder's equity per EME's
Ratio 67.5% balance sheet adjusted by comprehensive income after
December 31, 1999, plus (ii) senior recourse debt
- -------------------------------------------------------------------------------------------------------------------------------------
Discussion of Recourse Debt to Recourse Capital Ratio
The recourse debt to recourse capital ratio of EME at March 31, 2003 and December 31, 2002 was calculated as follows:
March 31, December 31,
In millions 2003 2002
- ------------------------------------------------------------------------------------------------------------------------------
Recourse Debt(1)
Corporate Credit Facilities $ 220 $ 140
Senior Notes 1,600 1,600
Guarantee of termination value of Powerton/Joliet
operating leases 1,433 1,452
Coal and Capex Facility 178 182
Other 31 30
- ------------------------------------------------------------------------------------------------------------------------------
Total Recourse Debt to EME $ 3,462 $ 3,404
- ------------------------------------------------------------------------------------------------------------------------------
Adjusted Shareholder's Equity(2) $ 2,049 $ 2,066
- ------------------------------------------------------------------------------------------------------------------------------
Recourse Capital(3) $ 5,511 $ 5,470
- ------------------------------------------------------------------------------------------------------------------------------
Recourse Debt to Recourse Capital Ratio 62.8% 62.2%
- ------------------------------------------------------------------------------------------------------------------------------
(1) Recourse debt means senior direct obligations of EME or obligations related to indebtedness or rental expenses
of one of its subsidiaries for which EME has provided a guarantee.
(2) Adjusted shareholder's equity is defined as the sum of total shareholder's equity and equity preferred
securities, less changes in accumulated other comprehensive gain or loss after December 31, 1999.
(3) Recourse capital is defined as the sum of adjusted shareholder's equity and recourse debt.
During the three months ended March 31, 2003, the recourse debt to recourse capital ratio was slightly higher due to:
o $80 million drawdown on corporate line of credit to cover seasonal working capital needs as well as cash collateral for
hedging; and
o reduction in adjusted shareholder's equity as a result of EME's $17 million net loss for the three months ended March 31,
2003.
EME Subsidiary Financing Plans
The estimated capital and construction expenditures of EME's subsidiaries for the final three quarters of 2003 total $56 million.
These expenditures are planned to be financed by existing subsidiary credit
Page 38
agreements and cash generated from their operations, except with respect to the Homer City project. Under the Homer City
sale-leaseback agreements, EME has committed to provide funds for capital expenditures needed to complete the Homer City
environmental improvement project. EME expects to contribute $17 million in 2003 to fund the completion of this project, of which
$7 million was contributed during the first quarter of 2003.
Edison Mission Midwest Holdings
EME's wholly owned subsidiary, Edison Mission Midwest Holdings, had long-term debt with the following maturities at March 31, 2003:
Amount
(In millions) Due Date
- ----------------------------------------------------------------------------------------------------
$ 911 December 2003
808 December 2004
- ----------------------------------------------------------------------------------------------------
$ 1,719
- ----------------------------------------------------------------------------------------------------
In addition, Edison Mission Midwest Holdings has a $150 million working capital facility (unused at March 31, 2003), which is
scheduled to expire in December 2004. At March 31, 2003, Edison Mission Midwest Holdings had cash and cash equivalents of $260
million, as well as $78 million deposited into a restricted cash account. Edison Mission Midwest Holdings is not expected to have
sufficient cash to repay the $911 million debt due in December 2003. Edison Mission Midwest Holdings plans to extend or refinance
the $911 million debt obligation prior to its expiration in December 2003. Completion of this extension or refinancing is subject to
a number of uncertainties, including the ability of the Illinois plants to generate funds during the remainder of 2003 and the
availability of new credit from financial institutions on acceptable terms in light of industry conditions. Accordingly, there is no
assurance that Edison Mission Midwest Holdings will be able to extend or refinance this debt when it becomes due or that the terms
will not be substantially different from those under the current credit facility.
Sunrise Project Financing
EME owns a 50% interest in Sunrise Power Company, which owns a natural gas-fired facility currently under construction in Kern
County, California, which EME refers to as the Sunrise project. The Sunrise project consists of two phases. Phase 1, a simple-cycle
gas-fired facility (320 MW), was completed on June 27, 2001. Phase 2, conversion to a combined-cycle gas-fired facility (bringing
the capacity to a total of 560 MW), is currently scheduled to be completed in July 2003. Sunrise Power Company entered into a
long-term power purchase agreement with the California Department of Water Resources on June 25, 2001. The agreement was amended on
December 31, 2002 as part of the settlement of several matters between Sunrise Power Company and the State of California. The
construction of the Sunrise project has been funded with equity contributions by its partners, including EME. Sunrise Power Company
has engaged a financial advisor to assist with obtaining project financing. Completion of project financing is subject to a number
of uncertainties, including market uncertainties and obtaining final environmental permits. EME believes that project financing will
be obtained in 2003, although no assurance can be provided in this regard. If project financing is completed by mid-2003, EME
estimates a distribution of approximately $140 million to $150 million from the proceeds of such financing.
EME's Intercompany Tax-Allocation Payments
EME is included in the consolidated federal and combined state income tax returns of Edison International and is eligible to
participate in tax-allocation payments with other subsidiaries of Edison International. These arrangements depend on Edison
International continuing to own, directly or indirectly, at least 80% of the voting power of the stock of EME and at least 80% of the
value of such
Page 39
stock. The arrangements are subject to the terms of tax allocation and payment agreements among Edison International, MEHC, EME and
other Edison International subsidiaries. The agreements to which EME is a party may be terminated by the immediate parent company of
MEHC at any time, by notice given before the first day of the first year with respect to which the termination is to be effective.
However, termination does not relieve any party of any obligations with respect to any tax year beginning prior to the notice. EME
has historically received tax-allocation payments related to domestic net operating losses incurred by EME. The right of EME to
receive tax-allocation payments and the amount and timing of tax-allocation payments are dependent on the inclusion of EME in the
consolidated income tax returns of Edison International and its subsidiaries, the amount of net operating losses and other tax items
of EME, its subsidiaries, and other subsidiaries of Edison International and specific procedures regarding allocation of state
taxes. EME receives tax-allocation payments for tax losses when and to the extent that the consolidated Edison International group
generates sufficient taxable income in order to be able to utilize EME's tax losses in the consolidated income tax returns for Edison
International and its subsidiaries. During the first quarter of 2003, EME received $13 million in tax-allocation payments from
Edison International. In the future, based on the application of the factors cited above, EME may be obligated during periods they
generate taxable income to make payments under the tax-allocation agreements.
Edison Capital's Liquidity Issues
Edison Capital expects to meet its operating cash needs through cash on hand, tax-allocation payments from the parent company and
expected cash flow from operating activities. As of March 31, 2003, Edison Capital had cash and cash equivalents of $419 million and
current liabilities of approximately $45 million. To the extent that specific funding conditions are satisfied, Edison Capital has
unfunded current and long-term commitments of $111 million for both affordable housing projects, and energy and infrastructure
investments. Under the tax-allocation agreement, Edison Capital paid approximately $32 million during the first quarter of 2003, as
Edison International amended its 2001 federal income tax return, which deferred realization of certain tax credits to future
periods. See "Financial Condition--Edison Capital's Intercompany Tax-Allocation Payments" section in the year-ended 2002 MD&A for
further discussion of the tax-allocation agreement. At March 31, 2003, Edison Capital's long-term debt had credit ratings of B2 and
B- from Moody's and Standard & Poor's, respectively.
COMMITMENTS
Edison International's long-term debt maturities and sinking fund requirements for the five twelve-month periods following March 31,
2003 are: 2004-- $1.9 billion; 2005-- $3.1 billion; 2006-- $733 million; 2007-- $1.7 billion; and 2008-- $458 million. These
amounts have been updated to reflect SCE's $966 million exchange offer that took place on February 24, 2003.
SCE has entered into six transition capacity contracts, which contain capacity payment provisions. SCE's commitments under these
contracts for the five twelve-month periods following March 31, 2003 are: 2004-- $66 million; 2005-- $69 million; 2006-- $69
million; 2007-- $69 million; and 2008-- $54 million.
MARKET RISK EXPOSURES
Edison International's primary market risk exposures include commodity price risk, interest rate risk and foreign currency exchange
risk that could adversely affect results of operations or financial position. Commodity price risk arises from fluctuations in the
market price of electricity, natural gas, oil, coal, and emission and transmission rights. Interest rate risk arises from
fluctuations in interest rates and foreign currency exchange risk arises from fluctuations in exchange rates. Edison International's
risk management policy allows the use of derivative financial instruments to manage its financial exposures,
Page 40
but prohibits the use of these instruments for speculative or trading purposes, except at EME's trading operations unit.
SCE's Market Risks
SCE's primary market risks include interest rate, generating fuel commodity price and credit 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 and to fund business operations, as well as to finance capital expenditures. The nature and amount of SCE's long-term and
short-term debt can be expected to vary as a result of future business requirements, market conditions and other factors. In
addition, SCE's return on common equity is set annually based on forecasts of interest rates and other factors.
Commodity Price Risk
Under the CPUC settlement agreement, SCE is permitted full recovery of its past procurement-related costs. Thereafter, SCE expects
to recover its reasonable power procurement costs in customer rates through regulatory mechanisms established in rate-making
proceedings. Assembly Bill (AB) 57, which the Governor of California signed in September 2002, provides that the CPUC shall adjust
rates, or order refunds, to amortize undercollections or overcollections of power procurement costs. Until January 1, 2006, the CPUC
must adjust rates if the undercollection or overcollection exceeds 5% of SCE's prior year's procurement costs, excluding revenue
collected for the CDWR. As a result of these regulatory mechanisms, changes in energy prices may impact SCE's cash flows but are not
expected to have an impact on earnings.
On January 1, 2003, SCE resumed procurement of its residual net short. SCE forecasts that its average 2003 residual net short, on an
energy basis, will be approximately 3% of the total energy needed to serve SCE's customers, with most of the short position occurring
during off-peak hours. SCE's residual net short exposure was larger during the first quarter of 2003, because of a planned refueling
outage at San Onofre Unit 3. In the second half of 2003, this exposure declines significantly as more power deliveries are scheduled
to commence under existing CDWR contracts that are allocated to SCE's customers. Factors that could cause SCE's residual net short
to be larger than expected include: direct access customers returning to utility service from their energy service provider; lower
utility generation; lower deliveries from QFs, CDWR or interutility contracts; and higher load requirements.
To reduce SCE's residual net short exposure, SCE entered into six transition capacity contracts with terms of up to 5 years. Through
fuel tolling arrangements, SCE is responsible for providing natural gas when the underlying contract facilities are called upon to
provide energy. SCE has not hedged its expected natural gas use for these capacity contracts. SCE anticipates it will need
additional capacity and/or ancillary services to hedge its peak requirement.
Pursuant to CPUC decisions, SCE arranges for natural gas and related services for the CDWR contracts allocated by the CPUC to SCE.
Financial and legal responsibility for the allocated contracts remains with the CDWR. Neither the CDWR, nor SCE, on behalf of the
CDWR, has hedged the expected natural gas requirements for the allocated contracts. To the extent the price of natural gas were to
increase above the levels assumed for cost recovery purposes, state law permits the CDWR to recover its actual costs through rates
established by the CPUC.
Page 41
EME's Market Risks
This subsection discusses commodity price risk at each of EME's market areas, as well as its risks associated with credit, interest
rates, foreign exchange rates and derivative financial instruments.
EME's primary market risk exposures are associated with the sale of electricity from and the procurement of fuel for its uncontracted
generating plants. These risks arise from fluctuations in electricity and fuel prices, emission and transmission rights, interest
rates and foreign currency exchange rates. EME manages these risks in part by using derivative financial instruments in accordance
with established policies and procedures. See "Current Developments" and "Financial Condition--EME's Liquidity Issues--EME's Credit
Ratings" for a discussion of market developments and their impact on EME's credit and the credit of its counterparties.
Commodity Price Risk
EME's merchant power plants and energy trading activities expose EME to commodity price risks. Commodity price risks are actively
monitored to ensure compliance with EME's risk management policies. Policies are in place, which define risk tolerances for each EME
regional business unit. Procedures exist, which allow for monitoring of all commitments and positions with regular reviews by a risk
management committee. EME performs a "value at risk" analysis in its daily business to measure, monitor and control its overall
market risk exposure. The use of value at risk allows management to aggregate overall commodity risk, compare risk on a consistent
basis and identify the drivers of the risk. Value at risk measures the possible loss over a given time interval, under normal market
conditions, at a given confidence level. Given the inherent limitations of value at risk and relying on a single risk measurement
tool, EME supplements this approach with the use of stress testing and worst-case scenario analysis, as well as stop loss limits and
counterparty credit exposure limits. Despite this, there can be no assurance that all risks have been accurately identified,
measured and/or mitigated.
Electric power generated at EME's domestic merchant plants is generally sold under bilateral arrangements with utilities and power
marketers under short-term transactions with terms of two years or less or, in the case of the Homer City facilities, to the PJM
and/or the New York Independent System Operator (NYISO) as well as utilities and power marketers. As discussed further below,
beginning in 2003, EME is selling a significant portion of the power generated from its Illinois plants into wholesale energy
markets. In order to provide more predictable earnings and cash flow, EME may hedge a portion of the electric output of its merchant
plants, the output of which is not committed to be sold under long-term contracts. When appropriate, EME manages the spread between
electric prices and fuel prices, and uses forward contracts, swaps, futures, or options contracts to achieve those objectives. There
is no assurance that contracts to hedge changes in market prices will be effective.
EME's revenue and results of operations during the estimated useful lives of its merchant power plants will depend upon prevailing
market prices for capacity, energy, ancillary services, fuel oil, coal and natural gas and associated transportation costs and
emission credits in the market areas where EME's merchant plants are located. Among the factors that influence the price of power in
these markets are:
o prevailing market prices for fuel oil, coal and natural gas and associated transportation costs;
o the extent of additional supplies of capacity, energy and ancillary services from current competitors or new market
entrants, including the development of new generation facilities;
o transmission congestion in and to each market area;
o the market structure rules to be established for each market area;
o the cost of emission credits or allowances;
Page 42
o the availability, reliability and operation of nuclear generating plants, where applicable, and the extended operation of nuclear
generating plants beyond their presently expected dates of decommissioning;
o weather conditions prevailing in surrounding areas from time to time; and
o the rate of electricity usage as a result of factors such as regional economic conditions and the implementation of
conservation programs.
A discussion of each market area is set forth below.
Illinois Plants
Electric power generated at the Illinois plants is sold under three power purchase agreements between EME's wholly owned subsidiary,
Midwest Generation, and Exelon Generation Company, under which Exelon Generation purchases capacity and has the right to purchase
energy generated by the Illinois plants. The agreements, which began on December 15, 1999 and expire in December 2004, provide for
capacity and energy payments. Exelon Generation is obligated to make a capacity payment for the plants under contract and an energy
payment for the electricity produced by these plants and taken by Exelon Generation. The capacity payments provide the revenue for
fixed charges, and the energy payments compensate the Illinois plants for variable costs of production.
Under each of the power purchase agreements, Exelon Generation, upon notice by a specified date, has the option to terminate each
agreement with respect to all or a portion of the units subject to it, as described below. As a result of notices given in 2002,
Exelon Generation released 4,548 MW of Midwest Generation's generating capacity from the power purchase agreements, thus increasing
Midwest Generation's reliance on sales into the wholesale markets. As a result, 4,739 MW remain subject to power purchase agreements
with Exelon Generation in 2003.
Under the power purchase agreement related to Midwest Generation's coal-fired generation units, Exelon Generation continues to have a
similar option, exercisable not later than 180 days prior to January 1, 2004, to retain or release for 2004 all or a portion of the
1,265 MW of option coal units retained for 2003. Exelon Generation remains committed to purchase the capacity of committed units
having 1,696 MW of capacity for both 2003 and 2004.
Under the power purchase agreements related to Midwest Generation's Collins Station and peaking units, Exelon Generation continues to
have a similar option to terminate, exercisable not later than 90 days prior to January 1, 2004, the power purchase agreements for
2004 with respect to all or a portion of the 1,084 MW from the Collins Station, and 694 MW from the peaking units, that were retained
for 2003.
The energy and capacity from any units, which are not subject to one of the power purchase agreements with Exelon Generation will be
sold under terms, including price and quantity, to be negotiated with customers through a combination of bilateral agreements,
forward energy sales and spot market sales. These arrangements generally have a term of two years or less. Thus, EME will be subject
to market risks related to the price of energy and capacity described above. EME expects that capacity prices for merchant energy
sales will, in the near term, be negligible in comparison to those Midwest Generation currently receives under its existing
agreements with Exelon Generation (with the possibility of minimal revenue due to the current oversupply conditions in this
marketplace). EME further expects that the lower revenue resulting from this difference will be offset in part by energy prices,
which EME believes will, in the near term, be higher for merchant energy sales than those Midwest Generation currently receives under
its existing agreements, as indicated below in the table of forward-looking prices. EME intends to manage this price risk, in part,
by accessing both the wholesale customer and over-the-counter
Page 43
markets described below as well as using derivative financial instruments in accordance with established policies and procedures.
During 2003, the primary markets available to Midwest Generation for wholesale sales of electricity from the Illinois plants are
expected to be "wholesale customer" and "over-the-counter." The most liquid over-the-counter markets in the Midwest region are sales
into the control area of Cinergy, referred to as "Into Cinergy," and, to a lesser extent, sales into the control area of Commonwealth
Edison, referred to as "Into ComEd" (due to geographic proximity, "Into ComEd" has been the primary market for Midwest Generation).
"Into Cinergy" and "Into ComEd" are bilateral markets for the sale or purchase of electrical energy for future delivery. Performance
of transactions in these markets is subject to contracts that generally provide for liquidated damages supported by a variety of
credit requirements, which may include independent credit assessment, parental guarantees, letters of credit and cash margining
arrangements.
The following table depicts the historical average market prices for energy per megawatt-hour "Into ComEd" and "Into Cinergy" for the
first three months of 2003:
Into ComEd* Into Cinergy*
Historical Energy Prices On-Peak(1) Off-Peak(1) 24-Hr On-Peak(1) Off-Peak(1) 24-Hr
- -----------------------------------------------------------------------------------------------------------------
January $ 37.06 $ 19.36 $ 30.97 $ 38.59 $ 29.91 $ 32.18
February 51.71 27.53 43.33 55.18 38.59 45.96
March 47.96 24.57 39.68 51.68 42.48 42.64
- -----------------------------------------------------------------------------------------------------------------
Quarterly Average $ 45.58 $ 23.82 $ 37.99 $ 48.48 $ 36.99 $ 40.26
- -----------------------------------------------------------------------------------------------------------------
(1) On-peak refers to the hours of the day between 7:00 a.m. and 11:00 p.m. Monday through Friday, excluding North
American Electric Reliability Council (NERC) holidays. All other hours of the week are referred to as off-peak.
* Source: Energy prices were determined by obtaining broker quotes and other public price sources, for both "Into
ComEd" and "Into Cinergy" delivery points.
The following table sets forth forward market prices for energy per megawatt-hour as quoted for sales "Into ComEd" and "Into Cinergy"
at March 31, 2003. These forward prices will continue to fluctuate as a result of a number of factors, including gas prices,
electricity demand, which is also affected by economic growth, and the amount of existing and planned power plant capacity. The
actual spot prices for electricity delivered into these markets may vary materially from the forward market prices.
Into ComEd* Into Cinergy*
Forward Energy Prices On-Peak(1) Off-Peak(1) 24-Hr On-Peak(1) Off-Peak(1) 24-Hr
- ----------------------------------------------------------------------------------------------------------------
2003
April $ 36.00 $ 18.00 $ 30.00 $ 40.25 $ 20.00 $ 33.50
May 33.81 18.75 25.55 38.21 21.25 28.91
June 35.50 19.25 26.83 40.38 21.50 30.31
July 45.18 20.25 32.04 50.50 23.25 36.14
August 44.18 20.25 31.06 49.50 23.25 35.10
September 31.43 17.00 23.73 35.75 19.25 26.95
October 28.50 16.25 22.31 34.00 18.25 26.04
November 29.50 17.25 22.42 35.00 19.25 25.90
December 30.50 18.25 24.05 36.00 20.25 27.70
2004 Calendar "strip"(2) 34.43 18.71 26.06 36.99 20.50 28.21
- ----------------------------------------------------------------------------------------------------------------
(1) On-peak refers to the hours of the day between 7:00 a.m. and 11:00 p.m. Monday through Friday, excluding NERC
holidays. All other hours of the week are referred to as off-peak.
Page 44
(2) Market price for energy purchases for the entire calendar year, as quoted for sales "Into ComEd" and
"Into Cinergy."
* Source: Energy prices were determined by obtaining broker quotes and other public price sources, for both "Into
ComEd" and "Into Cinergy" delivery points.
Midwest Generation intends to hedge a portion of its merchant portfolio risk through its marketing affiliate. To the extent it does
not do so, the unhedged portion will be subject to the risks and benefits of spot market price movements. The extent to which
Midwest Generation will hedge its market price risk through forward over-the-counter sales depends on several factors. First,
Midwest Generation will evaluate over-the-counter market prices to determine whether sales at forward market prices are sufficiently
attractive compared to assuming the risk associated with spot market sales. Second, Midwest Generation's ability to enter into
hedging transactions will depend upon its and its marketing affiliate's credit capacity and upon the over-the-counter forward sales
markets' having sufficient liquidity to enable Midwest Generation to identify counterparties who are able and willing to enter into
hedging transactions with it. Due to factors beyond Midwest Generation's control, market liquidity decreased significantly during
2002, and a number of formerly significant trading parties have completely withdrawn from the market or substantially reduced their
trading activities. See "--Credit Risks," below.
In addition to the prevailing market prices, Midwest Generation's ability to derive profits from the sale of electricity from the
released units will be affected by the cost of production, including costs incurred to comply with environmental regulations. The
costs of production of the released units vary and, accordingly, depending on market conditions, the amount of generation that will
be sold from the released units is expected to vary from unit to unit. In this regard, Midwest Generation suspended operations of
Will County Units 1 and 2 and Collins Station Units 4 and 5 at the end of 2002 pending improvement in market conditions. If market
conditions were to be depressed for an extended period of time, Midwest Generation would need to consider decommissioning these
units, which would result in a charge against income.
In addition to the price risks described previously, there are risks with respect to the availability and cost of transmission
required to market the power produced by the units not under contract with Exelon Generation. Currently, transmission must be
obtained from Commonwealth Edison under its open-access tariff filed with the FERC. In 2002, Commonwealth Edison applied to the FERC
for approval to join PJM in conjunction with American Electric Power, thereby creating an enlarged, contiguous regional transmission
organization encompassing a broad regional market. Approval of this application was granted by the FERC on April 1, 2003.
Concurrently, the ability of American Electric Power to join PJM has been brought into question by the enactment of legislation in
Virginia requiring the approval of Virginia state authorities for any transfer of control from American Electric Power to PJM of
American Electric Power transmission assets located in Virginia. On April 16, 2003, Commonwealth Edison and PJM issued a joint press
release stating that the integration of Commonwealth Edison into PJM would proceed separately from that of American Electric Power,
notwithstanding the absence of a direct transmission link owned by Commonwealth Edison between its service territory and the existing
PJM. In response to this announcement, EME and other affected parties have filed with the FERC for clarification or rehearing of its
April 1, 2003 order, and essentially contesting the appropriateness of Commonwealth Edison joining PJM on an "islanded" basis. Given
the stated intentions of Commonwealth Edison and PJM to proceed with integration beginning June 1, 2003, EME has requested expedited
treatment of its request for clarification or rehearing.
Midwest Generation's ability to transmit energy to counterparty delivery points to consummate spot sales and hedging transactions may
be affected by transmission service limitations and constraints and new standard market design proposals proposed by and currently
pending before the FERC. Although the FERC and the relevant industry participants are working to minimize such issues, Midwest
Generation cannot determine how quickly or how effectively such issues will be resolved.
Page 45
Homer City Facilities
Electric power generated at the Homer City facilities is sold under bilateral arrangements with domestic utilities and power
marketers pursuant to transactions with terms of two years or less, or to the PJM or the NYISO. These pools have short-term markets,
which establish 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. The Homer City facilities can also transmit
power to the Midwestern United States.
The following table depicts the average market prices per megawatt-hour in PJM during the first quarters of 2003 and 2002:
24-Hour PJM
Historical Energy Prices*
- ---------------------------------------------------------------------------------------------------------------
2003 2002
- ---------------------------------------------------------------------------------------------------------------
January $ 36.56 $ 20.52
February 46.13 20.62
March 46.85 24.27
- ---------------------------------------------------------------------------------------------------------------
Quarterly Average $ 43.18 $ 21.80
- ---------------------------------------------------------------------------------------------------------------
* Energy prices were calculated at the Homer City busbar (delivery point) using historical
hourly prices provided on the PJM-ISO web-site.
As shown on the above table, the average historical market prices at the Homer City busbar (delivery point) during the first three
months of 2003 were significantly higher than the average historical market prices during the first three months of 2002. Forward
market prices in PJM fluctuate as a result of a number of factors, including natural gas prices, transmission congestion, changes in
market rules, electricity demand, which is affected by weather and economic growth, and the amount of existing and planned power
plant capacity. The actual spot prices for electricity delivered into these markets may vary materially from the forward market
prices.
Sales made in the real-time or day-ahead market receive the actual spot prices at the Homer City busbar. In order to mitigate price
risk from changes in spot prices at the Homer City busbar, EME may enter into forward contracts with counterparties for forecasted
generation in future periods. Currently, there is not a liquid market for entering into forward contracts at the Homer City busbar.
A liquid market does exist for delivery to a collection of delivery points known as PJM West Hub, which EME's price risk management
activities use to enter into forward contracts. EME's revenue with respect to such forward contracts include:
o sales of actual generation in the amounts covered by such forward contracts with reference to PJM spot prices at the Homer
City busbar, plus or minus,
o sales to third parties under such forward contracts at designated delivery points (generally the PJM West Hub) less the cost
of purchasing power at spot prices at the same designated delivery points to fulfill obligations under such forward contracts.
Under the PJM market design, locational marginal pricing (sometimes referred to as LMP) has the effect of reducing prices at those
delivery points affected by transmission congestion and raising prices at points which are free of the congestion. During the past
12 months, an increase in transmission congestion between the Homer City facilities and delivery points east has resulted in prices
at the Homer City facilities being lower than those at PJM West Hub, which is east of the Homer City facilities. Thus, while forward
prices at PJM West Hub have historically been higher than the prices at the Homer City
Page 46
busbar by less than 5%, increased congestion during the last 12 months between the Homer City facilities and points east has resulted
in prices at PJM West Hub being on average 11% higher than those at the Homer City busbar.
By entering into forward contracts using the PJM West Hub as the delivery point, EME is exposed to "basis risk," which occurs when
forward contracts are executed on a different basis (in this case, PJM West Hub) than the actual point of delivery (Homer City
busbar). In order to mitigate basis risk resulting from forward contracts using PJM West Hub as the delivery point, EME has
participated in purchasing firm transmission rights in PJM, and may continue to do so in the future. A firm transmission right
provides the holder with a financial instrument to receive actual spot prices at one point of delivery and pay spot prices at another
point of delivery. Accordingly, EME's price risk management activities include using firm transmission rights alone or in
combination with forward contracts to manage changes in prices within the PJM market.
The following table sets forth the forward market prices for energy per megawatt-hour as quoted for sales into the PJM West Hub at
March 31, 2003:
24-Hour PJM West
Forward Energy Prices*
- ---------------------------------------------------------------------------------------------------------------
2003
- ---------------------------------------------------------------------------------------------------------------
April $ 42.67
May 41.43
June 44.10
July 53.24
August 49.55
September 39.43
October 36.28
November 34.86
December 36.60
- ---------------------------------------------------------------------------------------------------------------
2004 Calendar "strip"(1) 34.97
- ---------------------------------------------------------------------------------------------------------------
(1) Market price for energy purchases for the entire calendar year, as quoted for sales
into the PJM West Hub.
* Energy prices were determined by obtaining broker quotes and other public sources for
the PJM West Hub delivery point. Forward prices at PJM West are generally higher
than the prices at the Homer City busbar.
The ability of EME's subsidiary, EME Homer City, to make payments under the long-term lease entered into as part of the
sale-leaseback transaction discussed under "Off-Balance Sheet Transactions--EME's Off-Balance Sheet Transactions--Sale-Leaseback
Transactions," in the year-ended 2002 MD&A, depends on revenue generated by the Homer City facilities, which depend in part on the
market conditions for the sale of capacity and energy. These market conditions are beyond EME's control.
New Zealand
Contact Energy generates about a quarter of New Zealand's electricity and is the largest retailer of natural gas and electricity in
New Zealand. A substantial portion of Contact Energy's generation output is matched with the demand of its retail electricity
customers or sold through forward contracts with other wholesale electricity counterparties. The forward contracts and/or option
contracts have varying terms that expire on various dates through June 30, 2010, although the majority of the forward contracts are
short term (less than two years).
Page 47
The New Zealand Government released a Government Policy Statement in December 2001, which called for the industry to rationalize the
three existing industry codes, form a single governance structure and address transmission investment and pricing issues.
During 2001, an amendment to the Electricity Act of 1992 was passed that laid out the form that regulation would take if the industry
does not heed the government's call. A draft single governance code was presented to the New Zealand Commerce Commission for
approval early in 2002. In October 2002, the Commerce Commission approved the new arrangements in the form of a rulebook for the
self-governance of the electricity sector, with some conditions attached. The market participants are currently voting to determine
whether the rulebook will be adopted. It is currently anticipated that the vote will not succeed and that a government-imposed body
will be formed. The New Zealand Government is therefore currently progressing with plans for a Crown Electricity Governance Board,
which is likely to be substantially based on the single rule book created following the earlier Government Policy Statement. Under
this model, the Governance Board will be responsible for acting on government policy and will implement measures approved by
regulation.
While these arrangements have been progressing, several events in the months leading to the winter of 2003 in New Zealand have raised
concerns about the security of supply in the country. Wholesale electricity prices have risen in response to: dry hydro conditions,
higher-than-expected demand, and anticipated restrictions on the availability of thermal fuel. Further, there are concerns that new
investment in generation has not been forthcoming with the risk that similar shortages may arise in subsequent years. In March 2003,
the Government responded to these conditions by suggesting that significant changes may be required to the electricity market to
avoid the risk of insufficient supply in the future. In early May 2003, the Government issued a statement suggesting that the market
would be retained, but that a mechanism would be introduced to operate alongside the market to ensure that there is sufficient
standby generation to meet potential shortages in the future. Fuller details of this mechanism are expected to be announced towards
the end of May 2003 or in June 2003.
Credit Risks
In conducting EME's price risk management and trading activities, EME contracts with a number of utilities, energy companies and
financial institutions. Due to factors beyond EME's control, market liquidity has decreased significantly since the beginning of
2002, and a number of formerly significant trading parties have completely withdrawn from the market or substantially reduced their
trading activities. The reduction in the credit quality of traditional trading parties increases EME's credit risk. In addition, the
decrease in market liquidity may require EME to rely more heavily on wholesale electricity sales to wholesale customer markets, which
may also increase EME's credit risk. While various industry groups and regulatory agencies have taken steps to address market
liquidity, transparency and credit issues, there is no assurance as to when, or how effectively, such efforts will restore market
confidence. In the event a counterparty were to default on its trade obligation, EME would be exposed to the risk of possible loss
associated with reselling the contracted product at a lower price if the non-performing counterparty were unable to pay the resulting
liquidated damages owed to EME. Further, EME would be exposed to the risk of non-payment of accounts receivable accrued for products
delivered prior to the time such counterparty defaulted.
To manage credit risk, EME looks at the risk of a potential default by its counterparties. Credit risk is measured by the loss EME
would record if its counterparties failed to perform pursuant to the terms of their contractual obligations. EME has established
controls to determine and monitor the creditworthiness of counterparties and uses master netting agreements whenever possible to
mitigate its exposure to counterparty risk. EME may require counterparties to pledge collateral when deemed necessary. EME tries to
manage the credit in its portfolio based on credit ratings using published ratings of counterparties and other publicly disclosed
information, such as financial statements, regulatory
Page 48
filings, and press releases, to guide it in the process of setting credit levels, risk limits and contractual arrangements including
master netting agreements. The credit quality of EME's counterparties is reviewed regularly by EME's risk management committee. In
addition to continuously monitoring its credit exposure to its counterparties, EME also takes appropriate steps to limit or lower
credit exposure. Despite this, there can be no assurance that EME's actions to mitigate risk will be wholly successful or that
collateral pledged will be adequate.
EME measures credit risk exposure from counterparties of its merchant energy activities by the sum of: (i) 60 days of accounts
receivable, (ii) current fair value of open positions, and (iii) a credit value at risk. EME's subsidiaries enter into master
agreements and other arrangements in conducting price risk management and trading activities, which typically provide for a right of
setoff in the event of bankruptcy or default by the counterparty. Accordingly, EME's credit risk exposure from counterparties is
based on net exposure under these agreements. The credit ratings of EME's counterparties were as follows:
In millions March 31, 2003
- -------------------------------------------------------------------------------------------------------------
S&P Credit Rating:
A or higher $ 31
A- 10
BBB+ 67
BBB 56
BBB- 1
- -------------------------------------------------------------------------------------------------------------
Total $ 165
- -------------------------------------------------------------------------------------------------------------
Exelon Generation accounted for 19% and 30% of nonutility power generation revenue for the first quarters of 2003 and 2002,
respectively. The percentage is less in 2003 because a smaller number of plants are subject to contracts with Exelon Generation.
See "--Commodity Price Risk--Illinois Plants." Any failure of Exelon Generation to make payments to Midwest Generation under the power
purchase agreements could result in a shortfall of cash available for Midwest Generation to meet its obligations. A default by
Midwest Generation in meeting its obligations could in turn have a material adverse effect on EME.
EME's contracted power plants and the plants owned by unconsolidated affiliates in which EME owns an interest sell power under
long-term power purchase agreements. Generally, each plant sells its output to one counterparty. Accordingly, a default by a
counterparty under a long-term power purchase agreement, including a default as a result of a bankruptcy, would likely have a
material adverse affect on the operations of such power plant.
Edison Capital's Market Risks
Edison Capital is exposed to interest rate risk, foreign currency exchange rate risk and credit and performance risk that could
adversely affect its results of operations or financial position.
Credit and Performance Risk
Edison Capital has leased three aircraft to American Airlines. American Airlines is reporting significant operating losses, and
there is concern that American Airlines may file bankruptcy. If American files bankruptcy, or otherwise defaults in making its lease
payments, the lenders with a security interest in the aircraft or leases may exercise remedies that could lead to a loss of some or
all of Edison Capital's investment in the aircraft plus any accrued interest. The total maximum loss exposure to Edison Capital in
2003 is $48 million. A voluntary restructure of the lease could also result in a loss of some or all of the investment. At March
31, 2003, American Airlines was current in its lease payments and was publicly expressing a desire to avoid bankruptcy.
Page 49
SCE'S REGULATORY MATTERS
This section of MD&A presents updates to SCE's regulatory matters using three main subsections: generation and power procurement,
transmission and distribution, and other regulatory matters.
Generation and Power Procurement
CPUC Litigation Settlement Agreement
In 2001, SCE and the CPUC entered into a settlement of SCE's lawsuit against the CPUC, which sought a ruling that SCE is entitled to
full recovery of its past procurement-related costs. A key element of the settlement agreement was the establishment of a $3.6
billion rate-recovery mechanism called the PROACT as of August 31, 2001. Other provisions of the settlement agreement are described
in the "CPUC Litigation Settlement Agreement" disclosure in the year-ended 2002 MD&A. TURN, a consumer advocacy group, and other
parties appealed to the federal court of appeals seeking to overturn the stipulated judgment of the district court that approved the
settlement agreement. On March 4, 2002, the United States Court of Appeals for the Ninth Circuit heard argument on the appeal, and
on September 23, 2002 the court issued its opinion.
In its opinion, the federal court of appeals affirmed the district court on all claims, with the exception of the challenges founded
upon California state law, which the appeals court referred to the California Supreme Court. In sum, the appeals court concluded
that none of the substantive arguments based on federal statutory or constitutional law compelled reversal of the district court's
approval of the stipulated judgment.
However, the appeals court stated in its opinion that there is a serious question whether the settlement agreement violated state
law, both in substance and in the procedure by which the CPUC agreed to it. The appeals court added that if the settlement agreement
violated state law, the CPUC lacked capacity to consent to the stipulated judgment, and the stipulated judgment would need to be
vacated. The appeals court indicated that, on a substantive level, the stipulated judgment appears to violate California's electric
industry restructuring statute providing for a rate freeze. The appeals court also indicated that, on a procedural level, the
stipulated judgment appears to violate California laws requiring open meetings and public hearings. Because federal courts are bound
by the pronouncements of the state's highest court on applicable state law, and because the federal appeals court found no
controlling precedents from California courts on the issues of state law in this case, the appeals court issued a separate order
certifying those issues in question form to the California Supreme Court and requested that the California Supreme Court accept
certification.
The California Supreme Court accepted the certification, reformulated one of the certified questions as SCE had requested, and set a
briefing schedule that will be followed by oral argument. SCE and the CPUC filed their respective opening briefs concerning the
merits of the certified questions on December 20, 2002. TURN filed its answering brief on January 24, 2003 and SCE and the CPUC
filed reply briefs on February 13, 2003. In addition, the California Supreme Court requested that the parties provide supplemental
briefing with respect to an issue related to California's open meeting laws. The parties have complied with this directive from the
court. Various third parties, including the Governor of California, submitted friend-of-the-court briefs concerning the certified
questions, and SCE and TURN filed answering briefs, which responded to various points raised in the friend-of-the-court briefs. The
California Supreme Court has scheduled oral arguments for May 27, 2003. Once the California Supreme Court issues its decision on the
certified questions, the matter will return to the Ninth Circuit, which in turn should be guided by the California Supreme Court's
answers and interpretations of state law. In the meantime, the case is stayed in the federal appellate court. SCE continues to
operate under the settlement agreement. SCE continues to believe it is probable that SCE ultimately will recover its past
Page 50
procurement costs through regulatory mechanisms, including the PROACT. However, SCE cannot predict with certainty the outcome of the
pending legal proceedings.
PROACT Regulatory Asset
In accordance with the settlement agreement and an implementing resolution adopted by the CPUC, in the fourth quarter of 2001, SCE
established the PROACT regulatory balancing account, with an initial balance of $3.6 billion reflecting the net amount of past
procurement-related liabilities to be recovered by SCE. Each month, SCE applies to the PROACT the positive or negative difference
between SCE's revenue from retail electric rates (including surcharges) and the costs that SCE is authorized by the CPUC to recover
in retail electric rates. The balance in the PROACT regulatory balancing account was $574 million at December 31, 2002, $640 million
at March 31, 2003 and $512 million at April 30, 2003. The balance in the PROACT reflects the transfer of $209 million of risk
management hedging costs allowed by the CPUC in February 2003, an allocation adjustment for CDWR energy purchases and reduced surplus
revenue used to recover PROACT due to the San Onofre outage. SCE believes it will recover the PROACT balance during the summer of
2003. Potential factors that could change SCE's estimate of the timing of PROACT recovery are described in the "PROACT Regulatory
Asset" disclosure in the year-ended 2002 MD&A.
The following is an update on various regulatory proceedings impacting the timing of PROACT recovery:
Direct Access Proceedings
Direct Access - Historical Procurement Charge
From 1998 through mid-September 2001, SCE's customers were able to choose to purchase power directly from an energy service provider
other than SCE (thus becoming direct access customers) or continue to purchase power from SCE. (Customers who continue to purchase
power from SCE are referred to as bundled service customers.) On March 21, 2002, the CPUC issued a final decision affirming that new
direct access arrangements entered into by SCE's customers after September 20, 2001 are invalid. This decision did not affect direct
access arrangements in place before that date. Direct access customers receive a credit for the generation costs SCE saves by not
serving them. Electric utility revenue is reported net of this credit. Because of this credit, direct access power purchases
resulted in additional undercollected power procurement costs to SCE during 2000 and 2001. On July 17, 2002, the CPUC issued an
interim decision to establish a nonbypassable historical procurement charge requiring direct access customers to pay $391 million of
SCE's past power procurement costs and directed SCE to reduce the PROACT balance by $391 million and create a new regulatory asset
for the same amount. Several parties filed applications for rehearing of the interim decision with the CPUC, which were later
denied. Several parties also filed petitions for review of the interim decision with the California Supreme Court. The petitions
filed with the California Supreme Court were held pending the CPUC's ruling on the applications for rehearing. In March 2003, two
petitions for review were filed with the California Supreme Court. SCE cannot predict with certainty the outcome of the petitions
before the California Supreme Court.
The historical procurement charge is to be collected from direct access customers by reducing their existing generation credit by
2.7(cent)per kWh (effective July 27, 2002) until the CPUC issued and implemented an order to determine a surcharge for direct access
customers' share of the CDWR's costs, as discussed in the paragraph below. Once that surcharge was implemented on January 1, 2003,
the contribution by direct access customers to the historical procurement charge was reduced from 2.7(cent)per kWh to 1(cent)per kWh for the
collection of the $391 million, with the remainder of the 2.7(cent)per kWh utilized for CDWR's costs associated with direct access
customers. On October 16, 2002, SCE filed a petition with the CPUC to modify the historical procurement charge interim decision to
provide that
Page 51
direct access customers be responsible for $497 million of SCE's past procurement costs. In subsequent testimony, SCE reduced its
request to $493 million. Evidentiary hearings on SCE's petition to modify were held on March 4, 2003, and a decision is expected in
mid-2003. Once the interim decision becomes permanent, SCE will evaluate whether a new regulatory asset could be created. If such a
regulatory asset were created, the net effect of this action would be to accelerate PROACT recovery.
Direct Access - Exit Fees
On November 7, 2002, the CPUC issued a decision assigning responsibility for a portion of four other cost categories to the direct
access customers. The first category consists of the CDWR's power procurement costs incurred between January 17, 2001 and
September 30, 2001. The CDWR sold approximately $11 billion in bonds in fourth quarter 2002 to finance a portion of the costs
incurred during the California energy crisis. The CPUC decision stated that the direct access customers were responsible for paying
a portion of the CDWR bond charge to recover the principal and financing costs associated with these bonds. The second category
relates to the CDWR's power procurement costs for the last quarter of 2001 and the year 2002. The CPUC stated that direct access
customers must pay a share of these costs to make bundled service customers indifferent to suspension by the CPUC of the direct
access program on September 20, 2001. The third category includes the CDWR long-term contract costs for 2003 and beyond. The CPUC
decision stated that a portion of these costs must be paid by direct access customers to keep bundled service customers indifferent
to the later suspension of direct access on the premise that the CDWR signed some of its long-term contracts with the expectation of
serving the load that switched to direct access after July 1, 2001. Finally, the last category relates to the above-market costs of
SCE's utility retained generation (e.g., QFs' contract costs) that pursuant to AB 1890 are to be recovered from all customers on an
ongoing basis. The CPUC decision stated that: (1) the bond charge is applicable to all direct access customers except those who
were continuously on direct access and never used any CDWR power (less than 1% of SCE's load); (2) the next two categories of costs
are applicable to direct access customers who took bundled service at any time after February 1, 2001; and (3) the last category is
applicable to all direct access customers, including continuous direct access customers.
Evidentiary hearings to reassess the 2.7(cent)per kWh cap on the amount of exit fees to be paid by direct customers were conducted in
April 2003, and a decision is expected in May or June 2003. If revised, the new cap is expected to take effect on July 1, 2003. The
exact amount of exit fees to be paid by direct access customers will be determined on an annual basis after the CDWR's submits its
requested revenue requirement to the CPUC. In a separate decision, the CPUC adopted similar exit fees for customers who install
their own generation facilities or arrange to purchase power from another entity that installs generation facilities on or adjacent
to their property. In addition, the CPUC issued two proposed decisions to impose similar exit fees on customers whose load would be
served by a municipal entity.
Direct Access - Switching Exemptions
Under the switching exemptions, direct access customers with a pre-September 20, 2001 contract with an energy service provider are
allowed to switch back and forth between bundled service and direct access. In a May 8, 2003 decision, the CPUC allowed the
continuation of switching, but adopted rules to regulate and restrict it. Among these rules are:
o Direct access customers are only allowed to return to bundled service on a transitional basis for a period of 60 days, while
switching from one energy service provider to another, or for similar reasons where a temporary "safe harbor" is needed. After
this 60-day transition period, they must remain on bundled service for three years. While in the safe harbor these customers
must pay all incremental short term powers costs incurred on their behalf and the applicable direct access exit fees.
Page 52
o Direct access customers who switch back to bundled service other than for transition purposes must stay on bundled service for a
minimum three-year period.
o Direct access customers intending to return to bundled service for other than transition purposes must provide a six-month
advance notice. Similarly, if a customer intends to return to direct access after satisfying its three year minimum stay on
bundled service, it must provide six-months advance notice.
o Direct access customers returning to bundled service will be responsible for any exit fee undercollection, due to the 2.7(cent)
per kWh cap, incurred will they received direct access service.
The impact of the CPUC's decisions on direct access cost responsibilities are incorporated into SCE's current projection of the
timing of PROACT recovery.
Hedging Cost Recovery Decision
Pursuant to its authority mentioned in "--CPUC Litigation Settlement Agreement," SCE purchased $209 million in hedging instruments
(gas call options) in late 2001 to hedge a majority of its natural gas price exposure associated with QF contracts for 2002 and
2003. A February 13, 2003 CPUC decision allowed SCE to transfer the entire $209 million into the PROACT regulatory asset during
first quarter 2003. SCE has incorporated this decision into its current projection of the timing of PROACT recovery.
CDWR Power Purchases and Revenue Requirement Proceedings
In accordance with an emergency order signed by the governor, the CDWR began making emergency power purchases for SCE's customers on
January 17, 2001. Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR are remitted
directly to the CDWR and are not recognized as revenue by SCE. In February 2001, AB 1X (First Extraordinary Session, AB 1X) was
enacted into law. AB 1X authorized the CDWR to enter into contracts to purchase electric power and sell power at cost directly to
SCE's retail customers, and authorized the CDWR to issue bonds to finance electricity purchases. In addition, the CPUC is responsible
for allocating the CDWR's revenue requirement among the customers of SCE, Pacific Gas and Electric (PG&E), and San Diego Gas &
Electric (SDG&E).
As discussed in the "CDWR Power Purchases and Revenue Requirement Proceedings" disclosure in the year-ended 2002 MD&A, the CPUC has
allocated to SCE's customers: $3.5 billion of total power procurement revenue requirement of $9 billion for the period 2001 and
2002; $331 million of the 2003 bond charge revenue requirement of $745 million; and approximately $1.9 billion of the total 2003
power procurement revenue requirement of $4.5 billion. The CPUC has not yet ruled on issues relating to the true-up of the CDWR's
2001-2002 revenue requirement and the allocation to each utility. A true-up of the CDWR's revenue requirement, as well as the
additional allocation of contracts, is not incorporated into SCE's current projection of the timing of PROACT recovery.
Generation Procurement Proceedings
The CPUC's Order Instituting Rulemaking, issued in October 2001, establishes the policies and mechanisms necessary for SCE and the
other major California electric utilities to resume power procurement as of January 1, 2003. In 2002, the CPUC issued four
decisions: (1) on August 22, 2002, regarding transitional procurement contracts; (2) on September 19, 2002, regarding the allocation
of contracts previously entered into by the CDWR among the three major California utilities; (3) on October 24, 2002, for the
resumption of power procurement activities by these utilities on January 1, 2003, and adoption of a regulatory framework for such
activities; and (4) on December 19, 2002, concerning SCE's short-term procurement plan for 2003. See the "SCE's Regulatory Matters--
Page 53
Generation Procurement Proceedings" in the year-ended 2002 MD&A for detailed discussion of these matters. SCE has filed numerous
applications for rehearing and petitions for modifications of those decisions and, on March 4, 2003, filed a motion for consolidated
consideration urging the CPUC to conduct a comprehensive review of its procurement decisions.
On December 24, 2002 and January 14, 2003, SCE filed advice letters seeking CPUC approval of six renewable contracts provisionally
entered into by SCE pursuant to the August 22, 2002 decision on transitional procurement contracts. On January 30, 2003, the CPUC
issued a resolution approving four of the six contracts. An additional renewable contract was approved by the CPUC resolution issued
May 8, 2003. The CPUC is expected to rule on the remaining contract in the second quarter of 2003.
On February 3, 2003, SCE filed a petition for modification regarding the CPUC's December 19, 2002 decision. Among other things, the
petition requested clarification of the cap on SCE's maximum disallowance risk exposure and extension of the cap's scope to all
procurement activities. The CPUC has issued two proposed decisions. While both proposed decisions clarify the level of cap, only
one of them would expand the cap to cover all procurement-related activities. The proposed decisions, which are scheduled for
decision on May 22, 2003, largely adopt the other modifications requested. SCE also filed a second petition for modification, on
March 14, 2003, regarding hedging restrictions and the definition of least cost dispatch. No action has been taken on the second
petition.
In accordance with the CPUC's October 24, 2002 decision, SCE filed its long-term resource plan on April 15, 2003. SCE's long-term
resource plan included two plans, a preferred plan and an interim plan. The preferred plan contains long-term commitments that will
encourage investment in new generation and transmission infrastructure, increase long-term reliability and decrease price
volatility. These commitments include:
o a significant increase in cost-effective energy efficiency and demand response investments;
o renewable contracts that will meet or exceed the requirements of the Renewable Portfolio Standard (see below);
o a substantial increment of new utility or third-party owned generation resources; and
o at least two new major transmission projects that will provide the state of California access to a diverse set of generating
resources and help facilitate a more competitive wholesale market.
The interim plan, by contrast, relies exclusively on new short- and medium-term contracts with no long-term resource commitments
(except for new renewable contracts). In its filing, SCE maintained that implementation of its preferred plan requires resolution of
various issues including (1) stabilizing SCE's customer base; (2) restoring SCE's investment-grade creditworthiness;
(3) restructuring regulations regarding energy efficiency and demand response programs; (4) removing barriers to transmission
development; (5) modifying prior decisions, which impede long-term procurement; and (6) adopting a commercially realistic
cost-recovery framework that will enable utilities to obtain financing or enable contracting for new generation.
SCE expects to file its 2004 short-term procurement plan on May 15, 2003. Hearings on the short-term plan and certain key issues in
the long-term plan are expected to take place in July and August 2003.
As described in the year-ended 2002 MD&A, Senate Bill (SB) 1078 was signed into law in September 2002 and provides for SCE and other
California utilities to increase their procurement of renewable resources. Pursuant to a ruling of the CPUC's assigned
administrative law judge, issues related to implementation of Renewable Portfolio Standard issues in SB 1078 are being determined on
a separate,
Page 54
expedited schedule. Testimony on the implementation of SB 1078 was filed and hearings were held in April 2003. A preliminary
decision on Renewables Portfolio Standard issues is expected in June 2003, followed by a report by the CPUC to the Legislature on
June 30, 2003.
CDWR Contracts
On December 19, 2002, the CPUC adopted an operating order under which SCE, PG&E, and SDG&E perform the operational, dispatch, and
administrative functions for the CDWR's long-term power purchase contracts, beginning January 1, 2003. The operating order sets
forth the terms and conditions under which the three utility companies administer the CDWR contracts and requires the utility
companies to dispatch all the generating assets within their portfolios on a least-cost basis for the benefit of their ratepayers.
PG&E and SDG&E filed an emergency motion in which they sought to substitute their negotiated operating agreements with the CDWR for
the CPUC's operating order. In March 2003, the CPUC approved the negotiated operating agreements with the CDWR submitted by PG&E and
SDG&E, subject to certain modifications. Those modifications included eliminating provisions which would permit termination of the
agreements by the utilities, a provision which would permit additional guidance from the CDWR as to the performance of the utilities'
obligations, a provision which would permit the direct collection from the CDWR of fees for administering the CDWR contacts and
certain other provisions that permit the CDWR to direct the actions of the utilities under the contracts. The decision also required
PG&E, SDG&E and SCE to file gas supply plans for the purchase of natural gas for the CDWR contracts allocated to the utilities.
SCE's gas supply plan was filed on April 18, 2003. The CPUC also approved amendments to the servicing agreements between the
utilities and the CDWR relating to transmission, distribution, billing, and collection services for the CDWR's purchased power. The
servicing order issued by the CPUC identifies the formulas and mechanisms to be used by SCE to remit to the CDWR the revenue
collected from SCE's customers for their use of energy from the CDWR contracts that have been allocated to SCE.
Transmission and Distribution
2003 General Rate Case Proceeding
On May 3, 2002, SCE filed its formal application for the 2003 GRC, requesting a revenue requirement increase of $287 million over
2000 recorded revenue. The requested revenue increase is primarily related to capital additions, updated depreciation costs and
projected increases in pension and benefit expenses. In October 2002, the CPUC's Office of Ratepayer Advocates issued its testimony
and recommended a $172 million decrease in SCE's base rates. Several other intervenors have also proposed further reductions to
SCE's request or have made other substantive proposals regarding SCE's operations. Evidentiary hearings were concluded in March
2003. On April 18, 2003, SCE filed its post-hearing opening brief, reducing its requested increase from $286 million to $248
million. On April 30, 2003, the CPUC ordered SCE to shorten and refile its opening brief by May 14, 2003 and file a reply brief by
May 28, 2003.
During the proceeding, the CPUC's Office of Ratepayer Advocates was granted a three-month extension to submit its testimony, which
moved other procedural milestones by three months, including the expected date for a final decision. In response to the extension of
the proceeding schedule, SCE filed a motion requesting authorization to establish an account tracking SCE's requested revenue
requirement during the period between May 22, 2003, the date a final decision was originally expected, and the date a final decision
is adopted. This would effectively allow the final decision in the general rate case to apply to the account, with the amounts
tracked becoming subject to recovery or refund depending on the outcome of the proceeding. A proposed decision was issued approving
SCE's request to track the revenue requirement and is on the agenda for the CPUC's May 22, 2003 conference. A final decision on the
general rate case proceeding is expected in the third quarter of 2003.
Page 55
Cost of Capital Filing
SCE's annual cost of capital applications with the CPUC are required to be filed by May 8 of each year, with decisions rendered in
such proceedings becoming effective for the following year. On April 1, 2003, SCE filed a petition with the CPUC seeking to
eliminate the 2004 proceeding. This would result in SCE's 2003 cost of capital decision, issued on November 7, 2002, remaining in
effect throughout 2004. The CPUC has granted a temporary extension of SCE's filing deadline to July 8, 2003 while it considers SCE's
request. On April 24, 2003, the CPUC's Office of Ratepayer Advocates filed a response to SCE's petition supporting SCE's request for
eliminating the 2004 proceeding.
Transmission Overhead Proceeding
Since the initiation of the ISO in April 1998, transmission cost recovery has been under the FERC authority. In July 2000, the FERC
issued a final decision in SCE's 1998 FERC transmission rate case in which it ordered a reduction of approximately $38 million to
SCE's proposed annual base transmission revenue requirement of $213 million. Of the total reduction of $38 million, about $24 million
was associated with the FERC's rejection of SCE's proposed method for allocating overhead costs to transmission operations. SCE
filed for rehearing of the FERC decision in August 2000, asking that the FERC reconsider the decision assuming that the CPUC does not
allow SCE to recover the $24 million in CPUC jurisdictional rates. SCE continued to collect the $24 million annually in FERC rates
subject to refund until new transmission rates became effective on September 1, 2002. In February 2001, SCE filed with the CPUC a
request to recover in CPUC rates the overhead costs not permitted in FERC rates (amounting to $108 million as of March 31, 2003). On
May 6, 2003, the assigned CPUC administrative law judge issued a proposed decision rejecting the request. SCE intends to challenge
this proposed decision on the grounds that the costs at issue were already found to be reasonable by the CPUC in SCE's 1995 general
rate case, and SCE is being denied the recovery of these costs solely due to different methodologies employed by the CPUC and the
FERC for allocation of overhead costs which are not directly assignable to the transmission and distribution functions. A final CPUC
decision on this matter is expected in June 2003.
Wholesale Electricity and Gas Markets
In response to a consolidated proceeding related to the justness and reasonableness of rates charged by sellers in the PX and ISO
markets as described in the "SCE's Regulatory Matters--Wholesale Electricity Markets" disclosure in the year-ended 2002 MD&A, the FERC
issued orders that initiated procedures for determining additional refunds arising from market manipulation by energy suppliers. A
new FERC staff report issued on March 26, 2003 found that there was pervasive gaming and market manipulation of the electric and gas
markets in California and in the west coast and also described many of the techniques and effects of electric and gas market
manipulation. The FERC will be modifying the administrative law judge's initial decision of December 12, 2002 to reflect the fact
that the gas indices used in the market manipulation formula overstated the cost of gas used to generate electricity. Further
enforcement actions by the FERC are expected. SCE cannot, at this time, determine the timing or amount of any potential refunds.
Under the settlement agreement with the CPUC, any refunds will be applied to reduce the PROACT balance until the PROACT is fully
recovered. After PROACT recovery is complete, 90% of any refunds will be refunded to ratepayers.
Other Regulatory Matters
Customer Rate-Reduction Plan
On January 17, 2003, SCE filed with the CPUC a detailed plan outlining how customer rates could be reduced later in 2003 when SCE
expects to have completed recovery of uncollected procurement costs incurred on behalf of its customers during the California energy
crisis and reflected in the PROACT. In
Page 56
its January 17, 2003 filing, SCE proposed that the CPUC apply rate reductions of about $1.3 billion in the same manner it applied a
series of rate surcharges during the height of the energy crisis in 2001, primarily to rates paid by business and higher-use
residential customers. As originally proposed by SCE, after PROACT recovery is completed, bills for larger-use residential customers
would have declined 8%, and average rates reduced 19% for small and medium business customers and 26% for larger-use business
customers. Under a settlement reached with the active parties to the proceeding, somewhat different rate reductions for customer
groups have been proposed: 8% for residential, 18% for small business, 13% for medium business, and 19% for large business. The
settlement also calls for a modified procedure implementing those settlement rates, now with rates reduced sooner based on a forecast
of PROACT recovery rather than later based on verification. On April 23, 2003, SCE submitted the settlement to the CPUC for
approval. SCE cannot predict whether or not the CPUC will approve the settlement, or when.
ACQUISITIONS AND DISPOSITIONS
On March 3, 2003, Contact Energy, EME's 51% owned subsidiary, completed a transaction with NGC Holdings Ltd. to acquire the Taranaki
Combined Cycle power station and related interests. The Taranaki station is a 357 MW combined cycle, natural gas-fired plant located
near Stratford, New Zealand. Consideration for the Taranaki station consisted of a cash payment of approximately $275 million, which
was financed with bridge loan facilities. The bridge loan facilities were subsequently repaid with proceeds from the issuance of
long-term U.S. dollar denominated notes.
During the first quarter of 2002, EME completed the sales of its 50% interests in the Commonwealth Atlantic and James River projects
and its 30% interest in the Harbor project. Proceeds received from the sales were $44 million.
NEW ACCOUNTING STANDARDS
Effective January 1, 2003, Edison International adopted a new accounting standard, Accounting for Asset Retirement Obligations, which
requires entities to record the fair value of a liability for a legal asset retirement obligation in the period in which it is
incurred. When the liability is initially recorded, the entity capitalizes the cost by increasing the carrying amount of the related
long-lived asset. Over time, the liability is increased to its present value, and the capitalized cost is depreciated over the
useful life of the related asset. Upon settlement of the liability, an entity either settles the obligation for its recorded amount
or incurs a gain or loss upon settlement. However, rate-regulated entities may recognize regulatory assets or liabilities as a
result of timing differences between the recognition of costs in accordance with this standard and the recovery of costs through the
rate-making process. Regulatory assets and liabilities may also be recorded if it is probable that the asset retirement obligation
(ARO) will be recovered through the rate-making process.
Edison International's impact of adopting this standard was:
o SCE adjusted its nuclear decommissioning obligation to reflect the fair value of decommissioning its nuclear power
facilities. SCE also recognized AROs associated with the decommissioning of coal-fired generation assets.
o At December 31, 2002, SCE had accrued $2.3 billion to decommission its nuclear facilities and $12 million to decommission
its share of a coal-fired generating plant, under accounting principles in effect at that time. Of these amounts, $298 million
to decommission its inactive nuclear facility was recorded in other long-term liabilities, and the remaining $2.0 billion was
recorded as a component of the accumulated provision for depreciation and decommissioning on the consolidated balance sheets in
the 2002 Annual Report.
Page 57
o As of January 1, 2003, SCE reversed the $2.3 billion it had previously recorded for decommissioning, recorded the fair value of its
AROs of approximately $2.0 billion in the deferred credits and other liabilities section of the balance sheet, and increased its
unamortized nuclear investment by $303 million. The cumulative effect of a change in accounting principle from unrecognized
accretion expense and adjustments to depreciation, decommissioning and amortization expense recorded to date was a $354 million
after-tax gain, which under accounting standards for rate-regulated enterprises was deferred as a regulatory liability, partially
offset by a $235 million deferred tax asset, as of January 1, 2003. Accretion and depreciation expense resulting from the
application of the new standard is expected to be approximately $143 million in 2003. This cost will reduce the regulatory
liability, with no impact on earnings. As of March 31, 2003, SCE's ARO for its nuclear facilities totaled approximately
$2.0 billion and its nuclear decommissioning trust assets had a fair value of $2.1 billion. If the new standard had been in
place on January 1, 2002, SCE's ARO as of that date would have been $1.98 billion. Approximately $1.9 billion collected through
rates for cost of removal of plant assets not considered to be legal obligations remain in accumulated depreciation and
decommissioning.
o As of January 1, 2003, EME's ARO was $17 million and EME recorded a cumulative effect adjustment that decreased net income
by approximately $9 million, net of tax. If the new standard had been applied retroactively in the three months ended March 31,
2002, it would not have had a material effect on EME's results of operations.
In January 2003, an accounting interpretation was issued to address consolidation of variable-interest entities (VIEs). The primary
objective of the interpretation is to provide guidance on the identification of, and financial reporting for, entities over which
control is achieved through means other than voting rights; such entities are known as VIEs. This interpretation applies to VIEs
created after January 31, 2003 and beginning July 1, 2003 applies to VIEs in which an enterprise holds a variable interest that it
acquired before February 1, 2003.
If an enterprise absorbs the majority of the VIE's expected losses or receives a majority of the VIE's expected residual returns, or
both, it must consolidate the VIE. An enterprise that is required to consolidate the VIE is called the primary beneficiary.
Additional disclosure requirements are also applicable when an enterprise holds a significant variable interest in a VIE, but is not
the primary beneficiary. In addition, financial statements issued after January 31, 2003 must include certain disclosures if it is
reasonably possible that an enterprise will consolidate or disclose information about a VIE when this interpretation is effective.
Edison International has concluded that it is the primary beneficiary in several projects, including EME's Brooklyn Navy Yard project
and Edison Capital's Storm Lake project, since it is at risk with respect to the majority of its losses and is entitled to receive
the majority of its residual returns. Accordingly, effective July 1, 2003, Edison International will consolidate these projects,
which will increase total assets by approximately $447 million and total liabilities by approximately $528 million. Edison
International expects to record a loss of approximately $77 million (of which $71 million is related to Brooklyn Navy Yard) as a
cumulative accounting change as a result of consolidating these VIEs.
Edison International believes it is reasonably possible that certain partnership interests in energy projects are VIEs under this
interpretation, as discussed below:
Edison International owns certain partnership interests in seven energy partnerships, which own a combined 3,098 MW of power plants.
The maximum exposure to loss from EME's interest in these energy partnerships is $1.1 billion at March 31, 2003. Of this amount,
$542 million represents EME's investment in the 1,230 MW Paiton project and $305 million represents EME's investment in the 540 MW
EcoElectrica project.
Page 58
EME owns a 50% interest in TM Star, which was formed for the limited purpose of selling natural gas to another affiliated project
under a fuel supply agreement. TM Star has entered into fuel purchase contracts with unrelated third parties to meet a portion of
the obligations under the fuel supply agreement. EME has guaranteed 50% of the obligation under the fuel supply agreement to this
affiliated project. The maximum loss is subject to changes in natural gas prices. Accordingly, the maximum exposure to loss cannot
be determined.
Edison International is in the process of reviewing the entities discussed above that have a reasonable possibility of being VIEs to
determine if it is the primary beneficiary.
FORWARD-LOOKING INFORMATION AND RISK FACTORS
In the preceding MD&A and elsewhere in this quarterly report, the words estimates, expects, anticipates, believes, predict, and other
similar expressions are intended to identify forward-looking information that involves risks and uncertainties. Actual results or
outcomes could differ materially from those anticipated. Risks, uncertainties and other important factors that could cause results
to differ or that otherwise could impact Edison International and its subsidiaries, include, among other things:
o the outcome of the pending appeal of the stipulated judgment approving SCE's settlement agreement with the CPUC, and the
effects of other legal actions, if any, attempting to undermine the provisions of the settlement agreement or otherwise adversely
affecting SCE;
o the substantial amount of debt and lease obligations of MEHC, EME and their subsidiaries, including $911 million of debt
maturing in December 2003 and $275 million of a credit facility expiring in September 2003, which presents the risk that MEHC,
EME, and their subsidiaries might not be able to repay or refinance their obligations, raise additional financing for their
future cash requirements, or provide credit support for ongoing operations;
o the actions of securities rating agencies, including the determination of whether or when to make changes in ratings
assigned to Edison International and its subsidiaries that are rated, the ability of Edison International, SCE, EME and Edison
Capital to regain investment-grade ratings, and the impact of current or lowered ratings and other financial market conditions on
the ability of the respective companies to obtain needed financing on reasonable terms and provide credit support;
o changes in prices and availability of wholesale electricity, natural gas, other fuels, and transmission services, and other
changes in operating costs, which could affect the timing of SCE's energy procurement cost recovery, or otherwise impact SCE's
and EME's operations and financial results;
o the operation of some of EME's power plants without long-term power purchase agreements, which may adversely affect EME's
ability to sell the plant's output at profitable terms;
o the substantial amount of EME's revenue derived under power purchase agreements with a single customer, which could
adversely affect EME's results of operations and liquidity;
o changing conditions in wholesale power markets, such as general credit constraints and thin trading volumes, that could make
it difficult for EME or SCE to buy or sell power or enter into hedging agreements;
o provisions in MEHC's, EME's and their subsidiaries' organizational and financing documents that limit their ability to,
among other things, incur and repay debt, pay dividends, sell assets, and enter
Page 59
into specified transactions that they otherwise might enter into, which may impair their ability to compete effectively or to
operate successfully under adverse economic conditions;
o the possibility that existing tax allocation agreements may be terminated or may not operate as contemplated, for example,
if the consolidated group does not have sufficient taxable income to use the tax benefits of each group member, or if any member
ceases to be a part of the consolidated group;
o actions by state and federal regulatory and administrative bodies setting rates, adopting or modifying cost recovery,
holding company rules, accounting and rate-setting mechanisms, or otherwise changing the regulatory and business environments
within which Edison International and its subsidiaries do business, as well as legislative or judicial actions affecting the same
matters;
o the effects of increased competition in energy-related businesses, including new market entrants and the effects of new
technologies that may be developed in the future;
o threatened attempts by municipalities within SCE's service territory to form public power entities and/or acquire SCE's
facilities for customers;
o the credit worthiness and financial strength of Edison Capital's counterparties worldwide in energy and infrastructure
projects, including power generation, electric transmission and distribution, transportation, and telecommunications;
o the effects of declining interest rates and investment returns on employee benefit plans and nuclear decommissioning trusts;
o general political, economic and business conditions in the countries in which Edison International and its subsidiaries do
business;
o political and business risks of doing business in foreign countries, including uncertainties associated with currency
exchange rates, currency repatriation, expropriation, political instability, privatization and other issues;
o power plant operation risks, including equipment failures, availability, output and labor issues;
o new or increased environmental requirements that could require capital expenditures or otherwise affect the operations and
cost of Edison International and its subsidiaries, and possible increased liabilities under new or existing requirements; and
o weather conditions, natural disasters, and other unforeseen events.
Page 60
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information responding to Item 3 is included in Item 2, Management's Discussion and Analysis of Results of Operations and Financial
Condition, under Market Risk Exposures, and is incorporated herein by reference.
Item 4. Controls and Procedures
Under the Sarbanes-Oxley Act of 2002 and implementing rules and regulations adopted by the Securities and Exchange Commission (SEC),
Edison International must maintain disclosure controls and procedures. The term "disclosure controls and procedures" is defined in
the SEC's regulations to mean, as applied to Edison International, controls and other procedures that are designed to ensure that
information required to be disclosed by Edison International in reports filed with the SEC is recorded, processed, summarized, and
reported, within the time frames specified in the SEC's rules and forms. Disclosure controls and procedures include, without
limitation, controls and procedures designed to ensure that information required to be disclosed by Edison International in its SEC
reports is accumulated and communicated to Edison International's management, including its Chief Executive Officer and its Chief
Financial Officer, as appropriate to allow timely decisions regarding disclosure. The SEC's regulations also require Edison
International to carry out evaluations, under the supervision and with the participation of Edison International's management,
including its Chief Executive Officer and its Chief Financial Officer, of the effectiveness of the design and operation of Edison
International's disclosure controls and procedures. These evaluations must be carried out within the 90-day period prior to the
filing date of certain reports, including this Quarterly Report on Form 10-Q.
The Chief Executive Officer and the Chief Financial Officer of Edison International have evaluated the effectiveness of the design
and operation of Edison International's disclosure controls and procedures as of May 12, 2003. They have concluded that those
disclosure controls and procedures, as of the evaluation date, were effective in ensuring that information required to be disclosed
by Edison International in its reports filed with the SEC was (1) accumulated and communicated to Edison International's management,
as appropriate to allow timely decisions regarding disclosure, and (2) recorded, processed, summarized, and reported within the time
frames specified in the SEC's rules and forms.
The Chief Executive Officer and the Chief Financial Officer of Edison International also have concluded that there were no
significant changes in Edison International's internal controls or in other factors that could significantly affect those controls
subsequent to the date of their evaluation, including any corrective actions with regard to significant deficiencies and material
weaknesses.
Page 61
PART II - OTHER INFORMATION
Item 1. Legal Proceedings
Southern California Edison Company
Navajo Nation Litigation
As previously reported in Part I, Item 3 of Edison International's Annual Report on Form 10-K for the fiscal year ended December 31,
2002 (2002 Form 10-K), on June 18, 1999, SCE was served with a complaint filed by the Navajo Nation in the United States District
Court for the District of Columbia (D.C. District Court) against Peabody Holding Company and certain of its affiliates (Peabody),
Salt River Project Agricultural Improvement and Power District, and SCE. The complaint asserts claims against the defendants for,
among other things, violations of the federal RICO statute, interference with fiduciary duties and contractual relations, fraudulent
misrepresentation by nondisclosure, and various contract-related claims.
Some of the issues included in this case were recently addressed by the United States Supreme Court. The Navajo Nation had
previously filed suit in the Court of Claims against the United States Department of Interior, alleging that the Government had
breached its fiduciary duty concerning the above-referenced contract negotiations. On February 4, 2000, the Court of Claims issued a
decision in the Government's favor, finding that while there had been a breach, there was no available redress from the Government.
In its decision, the Court indicated that it was making no statements regarding, or findings in, the above federal civil court
action. The Navajo Nation filed an appeal and the Court of Appeals ruled that the Court of Claims did have jurisdiction to award
damages and remanded the case for that purpose. The United States filed for a Writ of Certiorari to the United States Supreme Court
which was granted. On March 4, 2003, the Supreme Court issued its majority decision reversing the decision of the Court of
Appeals. The Supreme Court concluded that there was no breach of a fiduciary duty and that the Navajo Nation did not have a right
to relief against the Government. Based on the Supreme Court's analysis, SCE filed on April 28, 2003, a motion to dismiss or, in the
alternative, for summary judgment in the D.C. District Court action. The motion remains pending.
CPUC Litigation and Settlement
As previously reported in Part I, Item 3 of Edison International's 2002 Form 10-K, in November 2000, SCE filed a lawsuit against the
CPUC in federal district court seeking a ruling that SCE is entitled to full recovery of its electricity procurement costs incurred
during the energy crisis in accordance with the tariffs filed with the FERC. See the discussion, which is incorporated herein by
this reference, in Part 1, Item 2, Management's Discussion and Analysis of Results of Operation and Financial Condition under "SCE'S
REGULATORY MATTERS - CPUC Litigation Settlement Agreement" for a description of SCE's lawsuit against the CPUC, its settlement, and
the appeal of the stipulated judgment approving the settlement.
DTSC Enforcement Action
SCE has received a Draft Enforcement Order and related documents from the California Department of Toxic Substances Control (DTSC),
seeking penalties totaling $383,400. The DTSC alleges that SCE failed, during a 13 month period ending in March 2002, to properly
maintain prescribed levels of financial assurance in connection with its on-site management of hazardous waste at the San Onofre
Nuclear Generating Station. SCE has the right to request a meeting with the DTSC, as well as to a hearing before an administrative
law judge, to resolve these allegations.
Page 62
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1 Restated Articles of Incorporation of Edison International dated May 9, 1996
(File No. 1-9936, Form 10-K for the year ended December 31, 1998)*
3.2 Certificate of Determination of Series A Junior Participating Cumulative Preferred Stock of Edison International
dated November 21, 1996 (Form 8-A dated November 21, 1996)*
3.3 Amended Bylaws of Edison International as adopted by the Board of Directors on January 1, 2002 (File No. 1-9936,
Form 10-K for year ended December 31, 2001)*
10.1 Terms of 2003 stock option and performance share awards under the Equity Compensation Plan or the 2000 Equity Plan
10.2 Retention Incentive Award for Harold B. Ray (File No. 1-2313, filed as Exhibit 10.2 to the SCE Form 10-Q for the
quarter ended March 31, 2003)*
99 Statement Pursuant to 18 U.S.C. 1350
- ----------------
* Incorporated by reference pursuant to Rule 12b-32.
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
December 20, 2002 January 9, 2003 5
January 17, 2003 January 17, 2003 5
Page 63
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
EDISON INTERNATIONAL
(Registrant)
By /s/ THOMAS M. NOONAN
---------------------------------
THOMAS M. NOONAN
Vice President and Controller
By /s/ KENNETH S. STEWART
---------------------------------
KENNETH S. STEWART
Assistant General Counsel and
Assistant Secretary
May 13, 2003
CERTIFICATION
I, JOHN E. BRYSON, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Edison International;
2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the
period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: May 13, 2003
/s/ JOHN E. BRYSON
------------------
JOHN E. BRYSON
Chairman of the Board, President and
Chief Executive Officer
CERTIFICATION
I, THEODORE F. CRAVER, JR., certify that:
1. I have reviewed this quarterly report on Form 10-Q of Edison International;
2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the
period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in
this quarterly report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report
is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the
audit committee of registrant's board of directors (or persons performing the equivalent function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal
controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in
internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant deficiencies and material weaknesses.
Date: May 13, 2003
/s/ THEODORE F. CRAVER, JR.
---------------------------
THEODORE F. CRAVER, JR.
Executive Vice President, Chief Financial Officer
and Treasurer