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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
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/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number 1-2313
SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)
CALIFORNIA 95-1240335
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue
(P. O. Box 800)
Rosemead, California 91770
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (626) 302-1212
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 (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 [ ] No [X]
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 434,888,104
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SOUTHERN CALIFORNIA EDISON COMPANY
INDEX
Page
No.
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Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Consolidated Statements of Income - Three Months
Ended March 31, 2003 and 2002 1
Consolidated Statements of Comprehensive Income -
Three Months Ended March 31, 2003 and 2002 1
Consolidated Balance Sheets - March 31, 2003
and December 31, 2002 2
Consolidated Statements of Cash Flows -
Three Months Ended March 31, 2003 and 2002 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 13
Item 3. Quantitative and Qualitative Disclosures About Market Risk 28
Item 4. Controls and Procedures 28
Part II. Other Information:
Item 1. Legal Proceedings 29
Item 6. Exhibits and Reports on Form 8-K 30
Signatures
Certifications
SOUTHERN CALIFORNIA EDISON COMPANY
PART I FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended
March 31,
- -------------------------------------------------------------------------------------------------------------------
In millions 2003 2002
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Operating revenue $ 1,823 $ 1,907
- -------------------------------------------------------------------------------------------------------------------
Fuel 58 52
Purchased power 452 255
Provisions for regulatory adjustment clauses - net 305 671
Other operation and maintenance 485 414
Depreciation, decommissioning and amortization 213 182
Property and other taxes 41 29
- -------------------------------------------------------------------------------------------------------------------
Total operating expenses 1,554 1,603
- -------------------------------------------------------------------------------------------------------------------
Operating income 269 304
Interest and dividend income 39 109
Other nonoperating income 27 10
Interest expense - net of amounts capitalized (124) (183)
Other nonoperating deductions (26) (4)
- -------------------------------------------------------------------------------------------------------------------
Net income before tax 185 236
Income tax 80 84
- -------------------------------------------------------------------------------------------------------------------
Net income 105 152
Dividends on preferred stock 3 6
- -------------------------------------------------------------------------------------------------------------------
Net income available for common stock $ 102 $ 146
- -------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended
March 31,
- -------------------------------------------------------------------------------------------------------------------
In millions 2003 2002
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income $ 105 $ 152
Other comprehensive income, net of tax:
Amortization of cash flow hedges 1 1
- -------------------------------------------------------------------------------------------------------------------
Comprehensive income $ 106 $ 153
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 1
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
In millions 2003 2002
- --------------------------------------------------------------------------------------------------------------------
(Unaudited)
ASSETS
Cash and equivalents $ 1,079 $ 992
Restricted cash 45 47
Receivables, less allowances of $24 and $36
for uncollectible accounts at respective dates 661 767
Accrued unbilled revenue 414 437
Fuel inventory 12 12
Materials and supplies, at average cost 159 159
Accumulated deferred income taxes - net -- 42
Regulatory assets - net 350 509
Prepayments and other current assets 164 57
- -------------------------------------------------------------------------------------------------------------------
Total current assets 2,884 3,022
- -------------------------------------------------------------------------------------------------------------------
Nonutility property - less accumulated provision
for depreciation of $32 and $29 at respective dates 157 154
Nuclear decommissioning trusts 2,147 2,210
Other investments 317 214
- -------------------------------------------------------------------------------------------------------------------
Total investments and other assets 2,621 2,578
- -------------------------------------------------------------------------------------------------------------------
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
- -------------------------------------------------------------------------------------------------------------------
Regulatory assets - net 3,609 3,838
Other deferred charges 633 629
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges 4,242 4,467
- -------------------------------------------------------------------------------------------------------------------
Total assets $ 20,037 $ 18,314
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 2
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
March 31, December 31,
In millions, except share amounts 2003 2002
- --------------------------------------------------------------------------------------------------------------------
(Unaudited)
LIABILITIES AND SHAREHOLDER'S EQUITY
Short-term debt $ -- $ --
Long-term debt due within one year 705 1,671
Preferred stock to be redeemed within one year 9 9
Accounts payable 751 745
Accrued taxes 835 699
Accumulated deferred income taxes - net 139 --
Other current liabilities 1,567 1,439
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 4,006 4,563
- -------------------------------------------------------------------------------------------------------------------
Long-term debt 5,119 4,504
- -------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes - net 2,540 2,658
Accumulated deferred investment tax credits 147 148
Customer advances and other deferred credits 647 964
Power-purchase contracts 259 309
Accumulated provision for pensions and benefits 401 356
Asset retirement obligations 2,006 --
Other long-term liabilities 155 152
- -------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 6,155 4,587
- -------------------------------------------------------------------------------------------------------------------
Commitments and contingencies
(Notes 2 and 3)
Preferred stock:
Not subject to mandatory redemption 129 129
Subject to mandatory redemption 141 147
- -------------------------------------------------------------------------------------------------------------------
Total preferred stock 270 276
- -------------------------------------------------------------------------------------------------------------------
Common stock (434,888,104 shares outstanding at each date) 2,168 2,168
Additional paid-in capital 342 340
Accumulated other comprehensive loss (16) (16)
Retained earnings 1,993 1,892
- -------------------------------------------------------------------------------------------------------------------
Total common shareholder's equity 4,487 4,384
- -------------------------------------------------------------------------------------------------------------------
Total liabilities and shareholder's equity $ 20,037 $ 18,314
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 3
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Three Months Ended
March 31,
- -------------------------------------------------------------------------------------------------------------------
In millions 2003 2002
- -------------------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Cash flows from operating activities:
Net income $ 105 $ 152
Adjustments to reconcile net income to
net cash provided (used) by operating activities:
Depreciation, decommissioning and amortization 213 182
Other amortization 24 25
Deferred income taxes and investment tax credits 9 (162)
Regulatory assets - long-term - net 69 537
Gas call options (15) (23)
Power contracts collateral (39) --
Other assets (37) 17
Other liabilities (23) 112
Changes in working capital:
Receivables and accrued unbilled revenue 129 377
Regulatory assets - short-term - net 159 83
Fuel inventory, materials and supplies -- (2)
Prepayments and other current assets (105) 25
Accrued interest and taxes 128 56
Accounts payable and other current liabilities 141 (2,343)
- -------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by operating activities 758 (964)
- -------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issuance costs (11) (31)
Long-term debt repaid (304) (400)
Bonds remarketed and funds held in trust -- 192
Redemption of preferred stock (5) --
Rate reduction notes repaid (62) (62)
Nuclear fuel financing - net -- (59)
Short-term debt financing - net -- (527)
Dividends paid (4) (27)
- -------------------------------------------------------------------------------------------------------------------
Net cash used by financing activities (386) (914)
- -------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (267) (229)
Net funding of nuclear decommissioning trusts (21) (6)
Sales of investments in other assets 3 2
- -------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities (285) (233)
- -------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and equivalents 87 (2,111)
Cash and equivalents, beginning of period 992 3,414
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Cash and equivalents, end of period $ 1,079 $ 1,303
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 4
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary to
present a fair statement 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 Southern California Edison's (SCE) 2002 Annual Report on
Form 10-K filed with the Securities and Exchange Commission.
Note 1. Summary of Significant Accounting Policies
Basis of Presentation
SCE's significant accounting policies were described in Note 1 of "Notes to Consolidated Financial Statements"
included in its 2002 Annual Report. SCE 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 Standard
Effective January 1, 2003, SCE 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 each period, 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 as recorded 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.
SCE'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.
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SOUTHERN CALIFORNIA EDISON COMPANY
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.
Stock-Based Employee Compensation
SCE has three stock-based employee compensation plans, which are described more fully in Note 7 of SCE's 2002
Annual Report. SCE 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 if SCE had used the fair-value accounting method.
Three Months Ended
March 31,
- ----------------------------------------------------------------------------------------------------------
In millions 2003 2002
- ----------------------------------------------------------------------------------------------------------
(Unaudited)
Net income available for common stock, as reported $ 102 $ 146
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 1 1
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 1 1
- ----------------------------------------------------------------------------------------------------------
Pro forma net income available for common stock $ 102 $ 146
- ----------------------------------------------------------------------------------------------------------
Page 6
SOUTHERN CALIFORNIA EDISON COMPANY
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 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 SCE'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 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
Page 7
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 hearings. SCE cannot predict with
certainty what effects this investigation or any subsequent actions by the CPUC may have on it.
Note 3. Contingencies
In addition to the matters disclosed in these Notes, SCE is involved in other legal, tax and regulatory
proceedings before various courts and governmental agencies regarding matters arising in the ordinary
Page 8
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
course of business. SCE believes the outcome of these other proceedings will not materially affect its results of
operations or liquidity.
Environmental Remediation
SCE 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.
SCE 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. SCE 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, SCE records the lower end of this reasonably
likely range of costs (classified as other long-term liabilities) at undiscounted amounts.
SCE's recorded estimated minimum liability to remediate its 40 identified sites is $100 million. The sites
include SCE's divested gas-fueled generation plants, for which SCE retained some liability after their sale. The
ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous
uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity
of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting
from investigatory studies; the possibility of identifying additional sites; and the time periods over which site
remediation is expected to occur. SCE believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $288 million. The upper limit of this range of costs
was estimated using assumptions least favorable to SCE 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.
SCE'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 SCE may be held responsible for
contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs
can be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the
next several years are expected to range from $15 million to $25 million. Recorded costs for the twelve months
ended March 31, 2002 were $22 million.
Page 9
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Based on currently available information, SCE 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, SCE 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
On August 7, 2002, Edison International received a notice from the Internal Revenue Service asserting
deficiencies in federal corporate income taxes for its 1994 to 1996 tax years. Included in these amounts are
deficiencies asserted against SCE. The vast majority of SCE's tax deficiencies are timing differences and,
therefore, amounts ultimately paid, if any, would benefit it as future tax deductions. SCE believes that it has
meritorious legal defenses to deficiencies asserted against it and believes that the ultimate outcome of this
matter will not result in a material impact on its results of operations or financial 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.
Page 10
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 primary insurance
available ($300 million). The balance is covered by the industry's retrospective rating plan that uses deferred
premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the 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
Page 11
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.
Note 4. 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 12
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 Southern California Edison Company (SCE) 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 SCE's MD&A for the calendar
year 2002 (the year-ended 2002 MD&A), which was included in SCE's 2002 annual report to shareholders and
incorporated by reference into SCE'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 SCE'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
discussion. 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 SCE's Annual Report on Form 10-K for the year ended December 31, 2002.
This MD&A includes information about SCE, a regulated public utility company providing electricity to retail
customers in central, coastal, and southern California.
CURRENT DEVELOPMENTS
As discussed in detail in "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.
RESULTS OF OPERATIONS
First Quarter 2003 vs. First Quarter 2002
Earnings
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 "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
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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.
Operating Revenue
Approximately 93% of operating 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, operating revenue during the third
quarter of each year is significantly higher than other quarters.
Operating 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 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.
Operating revenue is reported net of this credit. See "Regulatory Matters--Direct Access Proceedings" discussion
below.
Operating Expenses
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-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.
Page 14
Other operation and maintenance expense increased in 2003 primarily 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.
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.
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 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.
Other nonoperating deductions increased in 2003 mainly due to accruals for regulatory matters at SCE.
Income Taxes
Income taxes decreased in 2003 primarily due to a decrease in pre-tax income, partially offset by lower tax
expense in 2002 reflecting a favorable resolution of tax audits.
SCE's composite federal and state statutory rate was approximately 40.551% for both periods presented. The
higher effective tax rate of 44% realized in the first quarter of 2003 was primarily due to property related
flow-through taxes.
FINANCIAL CONDITION
Cash Flows from Operating Activities
Net cash provided by operating activities was $758 million in the first quarter of 2003 and net cash used by
operating activities was $964 million in the first quarter of 2002. The change was mainly due to the March 2002
repayment of past-due obligations, partially offset by higher overcollections used to recover regulatory assets.
The change was also due to timing of cash receipts and disbursements related to working capital items.
Cash Flows from Financing Activities
Net cash used by financing activities was $386 million in the first quarter of 2003 and $914 million in the first
quarter of 2002.
During the first quarter of 2003, 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.
Page 15
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 "Liquidity Issues").
Cash Flows from Investing Activities
Cash flows from investing activities are affected by additions to property and plant, primarily for transmission
and distribution assets, and funding of nuclear decommissioning trusts.
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 "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
"Regulatory Matters--CPUC Litigation Settlement Agreement"), SCE's access to the capital markets, and actions by
the CPUC.
Page 16
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 "Regulatory Matters--CPUC Litigation
Settlement Agreement,--CDWR Revenue Requirement Proceeding, and--Generation Procurement Proceedings" sections.
COMMITMENTS
SCE's long-term debt maturities and sinking fund requirements for the five twelve-month periods following March
31, 2003 are: 2004-- $705 million; 2005-- $1.3 billion; 2006-- $446 million; 2007-- $1.2 billion; and 2008--
$184 million. These amounts have been updated to reflect the $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
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
Page 17
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.
REGULATORY MATTERS
This section of MD&A presents updates to 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.
Page 18
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
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. Operating 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.
Page 19
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 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
Page 20
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.
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
Page 21
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 "Regulatory
Matters--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.
Page 22
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, 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
Page 23
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.
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 "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
Page 24
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 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.
NEW ACCOUNTING STANDARD
Effective January 1, 2003, SCE 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 each period, 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 as recorded 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.
SCE'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
Page 25
the accumulated provision for depreciation and decommissioning on the consolidated balance sheets in the 2002
Annual Report.
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.
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 SCE, 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 changes in prices and availability of wholesale electricity, natural gas, other fuels, 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 operations and financial results;
o the effects of declining interest rates and investment returns on employee benefit plans and nuclear
decommissioning trusts;
o changing conditions in wholesale power markets, such as general credit constraints and thin trading
volumes, that could make it difficult for SCE to enter into hedging agreements;
o the actions of securities rating agencies, including the determination of whether or when to make
changes in SCE's credit ratings, the ability of SCE to regain investment-grade ratings, and the impact of
current or lowered ratings and other financial market conditions on the ability of SCE to obtain needed
financing on reasonable terms;
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 SCE does business, as well as legislative or judicial
actions affecting the same matters;
Page 26
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 new or increased environmental requirements that could require capital expenditures or otherwise affect
the operations and cost of SCE, and possible increased liabilities under new or existing requirements; and
o weather conditions, natural disasters, and other unforeseen events.
Page 27
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), SCE must maintain disclosure controls and procedures. The term "disclosure controls
and procedures" is defined in the SEC's regulations to mean, as applied to SCE, controls and other procedures
that are designed to ensure that information required to be disclosed by SCE 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 SCE in its SEC reports is accumulated and communicated to SCE'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 SCE to carry out evaluations, under the
supervision and with the participation of SCE's management, including its Chief Executive Officer and its Chief
Financial Officer, of the effectiveness of the design and operation of SCE'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 SCE have evaluated the effectiveness of the design
and operation of SCE'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 SCE in its reports filed with the SEC was (1) accumulated and communicated to SCE'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 SCE also have concluded that there were no
significant changes in SCE'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 28
PART II OTHER INFORMATION
Item 1. Legal Proceedings
Navajo Nation Litigation
As previously reported in Part I, Item 3 of SCE'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 SCE'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 29
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1 Certificate of Amendment and Restated Articles of Incorporation of SCE effective June 1, 1993
(File No. 1-2313, Form 10-K for the year ended December 31, 1993)*
3.2 Certificate of Correction of Restated Articles of Incorporation of SCE dated effective
August 21, 1997 (File No. 1-2313, Form 10-Q for the quarter ended September 30, 1997)*
3.3 Amended Bylaws of Southern California Edison Company as adopted by the Board of Directors on
January 1, 2003 (File No. 1-2313, Form 10-K for year ended December 31, 2002)*
10.1 Terms of 2003 stock option and performance share awards under the Equity Compensation Plan or
the 2000 Equity Plan (File No. 1-9936, filed as Exhibit 10.1 to the Edison International Form
10-Q for the quarter ended March 31, 2003)*
10.2 Retention Incentive Award for Harold B. Ray
99 Statement Pursuant to 18 U.S.C. 1350
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
-------------- ---------- ----------------
January 13, 2003 January 17, 2003 5
February 4, 2003 February 5, 2003 5
- ------------------
* Incorporated by reference pursuant to Rule 12b-32.
Page 30
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.
SOUTHERN CALIFORNIA EDISON COMPANY
(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, ALAN J. FOHRER, certify that:
1. I have reviewed this quarterly report on Form 10-Q of SCE;
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 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/ ALAN J. FOHRER
--------------------------------
ALAN J. FOHRER
Chief Executive Officer
CERTIFICATION
I, W. JAMES SCILACCI, certify that:
1. I have reviewed this quarterly report on Form 10-Q of SCE;
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 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/ W. JAMES SCILACCI
---------------------------------------
W. JAMES SCILACCI
Senior Vice President and Chief Financial Officer