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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 September 30, 2002
OR
/ / Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from to
Commission File Number 1-2313
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
(Address of Principal 91770
Executive Offices) (Zip Code)
(626) 302-1212
(Registrant's telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13
or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (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 the number of shares outstanding of each of the issuer's classes of common stock, as of the
latest practicable date:
Class Outstanding at November 12, 2002
----------------------------------------------- -----------------------------------------
Common Stock, no par value 434,888,104
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SOUTHERN CALIFORNIA EDISON COMPANY
INDEX
Page
No.
Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Consolidated Statements of Income - Three and Nine Months
Ended September 30, 2002, and 2001 (Unaudited) 1
Consolidated Statements of Comprehensive Income -
Three and Nine Months Ended September 30, 2002,
and 2001 (Unaudited) 1
Consolidated Balance Sheets - September 30, 2002 (Unaudited),
and December 31, 2001 2
Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2002, and 2001 (Unaudited) 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 32
Item 4. Controls and Procedures 32
Part II. Other Information:
Item 1. Legal Proceedings 33
Item 6. Exhibits and Reports on Form 8-K 35
Signatures
Certifications
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SOUTHERN CALIFORNIA EDISON COMPANY
PART I FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
3 Months Ended 9 Months Ended
September 30, September 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Operating revenue $ 2,864 $ 2,726 $ 6,957 $ 5,830
- -------------------------------------------------------------------------------------------------------------------
Fuel 59 57 160 154
Purchased power 780 759 1,615 3,290
Provisions for regulatory adjustment clauses - net 889 (5) 1,255 (124)
Other operation and maintenance 474 432 1,410 1,293
Depreciation, decommissioning and amortization 189 161 578 479
Property and other taxes 27 28 83 86
Net gain on sale of utility plant (6) -- (6) (9)
- -------------------------------------------------------------------------------------------------------------------
Total operating expenses 2,412 1,432 5,095 5,169
- -------------------------------------------------------------------------------------------------------------------
Operating income 452 1,294 1,862 661
Interest and dividend income 48 25 211 76
Other nonoperating income 9 6 28 28
Interest expense - net of amounts capitalized (132) (221) (456) (581)
Other nonoperating deductions 16 (2) 7 (18)
- -------------------------------------------------------------------------------------------------------------------
Net income before taxes 393 1,102 1,652 166
Income tax 155 445 562 68
- -------------------------------------------------------------------------------------------------------------------
Net income 238 657 1,090 98
Dividends on preferred stock 4 6 15 17
- -------------------------------------------------------------------------------------------------------------------
Net income available for common stock $ 234 $ 651 $ 1,075 $ 81
- -------------------------------------------------------------------------------------------------------------------
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
3 Months Ended 9 Months Ended
September 30, September 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2002 2001 2002 2001
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income $ 238 $ 657 $ 1,090 $ 98
Other comprehensive income, net of tax:
Cumulative effect of change in accounting for derivatives -- -- -- 397
Unrealized gain (loss) on cash flow hedges 1 1 11 (420)
- -------------------------------------------------------------------------------------------------------------------
Comprehensive income $ 239 $ 658 $ 1,101 $ 75
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 1
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SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
In millions 2002 2001
- --------------------------------------------------------------------------------------------------------------------
(Unaudited)
ASSETS
Cash and equivalents $ 1,290 $ 3,414
Receivables, less allowances of $38 and $32
for uncollectible accounts at respective dates 979 1,093
Accrued unbilled revenue 582 451
Fuel inventory 11 14
Materials and supplies, at average cost 154 146
Accumulated deferred income taxes - net 85 433
Regulatory assets - net 61 83
Prepayments and other current assets 194 145
- -------------------------------------------------------------------------------------------------------------------
Total current assets 3,356 5,779
- -------------------------------------------------------------------------------------------------------------------
Nonutility property - less accumulated provision
for depreciation of $26 and $17 at respective dates 157 159
Nuclear decommissioning trusts 2,107 2,275
Other investments 195 224
- -------------------------------------------------------------------------------------------------------------------
Total investments and other assets 2,459 2,658
- -------------------------------------------------------------------------------------------------------------------
Utility plant, at original cost:
Transmission and distribution 13,858 13,568
Generation 1,754 1,729
Accumulated provision for depreciation and decommissioning (8,244) (7,969)
Construction work in progress 653 556
Nuclear fuel, at amortized cost 137 129
- -------------------------------------------------------------------------------------------------------------------
Total utility plant 8,158 8,013
- -------------------------------------------------------------------------------------------------------------------
Regulatory assets - net 4,862 5,528
Other deferred charges 521 475
- -------------------------------------------------------------------------------------------------------------------
Total deferred charges 5,383 6,003
- -------------------------------------------------------------------------------------------------------------------
Total assets $ 19,356 $ 22,453
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 2
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SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
In millions, except share amounts 2002 2001
- --------------------------------------------------------------------------------------------------------------------
(Unaudited)
LIABILITIES AND SHAREHOLDER'S EQUITY
Short-term debt $ -- $ 2,127
Long-term debt due within one year 872 1,146
Preferred stock to be redeemed within one year 9 105
Accounts payable 917 3,261
Accrued taxes 1,101 823
Other current liabilities 1,551 1,645
- -------------------------------------------------------------------------------------------------------------------
Total current liabilities 4,450 9,107
- -------------------------------------------------------------------------------------------------------------------
Long-term debt 5,573 4,739
- -------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes - net 2,882 3,365
Accumulated deferred investment tax credits 150 153
Customer advances and other deferred credits 804 739
Power-purchase contracts 300 356
Accumulated provision for pensions and benefits 528 420
Other long-term liabilities 155 148
- -------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 4,819 5,181
- -------------------------------------------------------------------------------------------------------------------
Commitments and contingencies
(Notes 2 and 4)
Preferred stock:
Not subject to mandatory redemption 129 129
Subject to mandatory redemption 147 151
- -------------------------------------------------------------------------------------------------------------------
Total preferred stock 276 280
- -------------------------------------------------------------------------------------------------------------------
Common stock (434,888,104 shares outstanding at each date) 2,168 2,168
Additional paid-in capital 343 336
Accumulated other comprehensive income (loss) (12) (22)
Retained earnings 1,739 664
- -------------------------------------------------------------------------------------------------------------------
Total common shareholder's equity 4,238 3,146
- -------------------------------------------------------------------------------------------------------------------
Total liabilities and shareholder's equity $ 19,356 $ 22,453
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 3
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SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
9 Months Ended
September 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2002 2001
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Cash flows from operating activities:
Net income $ 1,090 $ 98
Adjustments to reconcile net income to
net cash provided by operating activities:
Depreciation, decommissioning and amortization 578 479
Other amortization 78 60
Deferred income taxes and investment tax credits (493) (35)
Regulatory assets - long-term - net 1,003 (388)
Other assets 25 (93)
Other liabilities 111 60
Changes in working capital:
Receivables and accrued unbilled revenue (18) (620)
Regulatory liabilities - short-term - net 70 (59)
Fuel inventory, materials and supplies (6) (9)
Prepayments and other current assets (50) (71)
Accrued interest and taxes 225 258
Accounts payable and other current liabilities (2,354) 2,662
- -------------------------------------------------------------------------------------------------------------------
Net cash provided by operating activities 259 2,342
- -------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 1,600 --
Long-term debt repaid (1,000) --
Bonds remarketed (repurchased) and funds held in trust 191 (130)
Redemption of preferred securities (100) --
Rate reduction notes repaid (176) (174)
Nuclear fuel financing - net (59) (14)
Short-term debt financing - net (2,127) 680
Dividends paid (36) (1)
- -------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by financing activities (1,707) 361
- -------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (694) (525)
Net funding of nuclear decommissioning trusts 1 3
Sales of investments in other assets 17 11
- -------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities (676) (511)
- -------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and equivalents (2,124) 2,192
Cash and equivalents, beginning of period 3,414 583
- -------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of period $ 1,290 $ 2,775
- -------------------------------------------------------------------------------------------------------------------
The accompanying notes are an integral part of these financial statements.
Page 4
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments of a normal recurring nature necessary for a fair presentation of
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 have been included. The results of
operations for the period ended September 30, 2002, are not necessarily indicative of the operating results for
the full year.
Southern California Edison's (SCE) significant accounting policies were described in Note 1 of "Notes to
Consolidated Financial Statements" included in its 2001 Annual Report on Form 10-K filed with the Securities and
Exchange Commission. SCE follows the same accounting policies for interim reporting purposes.
The quarterly report should be read in conjunction with SCE's 2001 Annual Report on Form 10-K filed with the
Securities and Exchange Commission.
Note 1. New Accounting Standards
On January 1, 2001, SCE adopted a new accounting standard for derivative financial instruments and hedging
activities. Adoption of this standard had no material impact on SCE's financial statements. Effective April 1,
2002, SCE also adopted an authoritative accounting interpretation to this standard, which precludes fuel
contracts that have variable amounts from qualifying under the normal purchases and sales exception. The
adoption of this interpretation had no impact on SCE's financial statements.
A new accounting standard, Accounting for Asset Retirement Obligations, 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. The standard is
effective for SCE on January 1, 2003. SCE is studying the effects of the new standard and has not yet determined
the potential impact on its financial statements.
Note 2. Regulatory Matters
California Public Utilities Commission Litigation Settlement Agreement
Southern California Edison (SCE) and the California Public Utilities Commission (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. Specifically, the appeals court affirmed the district court in the following respects: (1) the
district court did not err in denying the motions to intervene brought by entities other than TURN; (2) the
district court did not err in denying standing for the entities other than TURN to appeal the stipulated
judgment; (3) the district court was not deprived of original jurisdiction over the lawsuit; (4) the district
court did not err in declining to abstain from the case; (5) the district court did not exceed its authority by
approving the stipulated judgment without TURN's consent; (6) the district court's approval of the settlement
agreement did not deny TURN due process; and (7) the district court did not violate the Tenth Amendment of the
United States Constitution in approving the stipulated judgment. In sum, the appeals court concluded that none
of the substantive arguments
Page 5
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 to the California Supreme Court and
requested that the California Supreme Court accept certification.
The appeals court stayed further proceedings in the case pending a response from the California Supreme Court on
the request for certification. The appeals court did not stay the continued operation of the settlement
agreement, thus collection of past procurement costs under PROACT is continuing. On October 29, 2002, SCE filed a
brief requesting that the California Supreme Court answer the appeals' court certification and requesting that
hearing of the matter be placed on the California Supreme Court's March 2003 calendar, or heard at the court's
earliest convenience. 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.
Under the settlement agreement, SCE cannot pay dividends or other distributions on its common stock (all of which
is held by its parent, Edison International) prior to the earlier of the date on which SCE has recovered all of
its procurement-related obligations or January 1, 2005, except that if SCE has not recovered all of its
procurement-related obligations by December 31, 2003, SCE may apply to the CPUC for consent to resume common
stock dividends prior to January 1, 2005, and the CPUC will not unreasonably withhold its consent.
In April 2002, the Foundation for Taxpayer and Consumer Rights (FTCR), an advocacy group, filed a petition in the
California Supreme Court against the CPUC. The FTCR's petition asserted that, among other things, the CPUC
exceeded its authority and violated state law in approving the settlement agreement and stipulated judgment with
SCE. The petition sought a declaration that the CPUC cannot agree not to enforce any state law unless an
appellate court has determined that the state law is invalid, unconstitutional, or unenforceable. The FTCR's
petition expressly stated that it did not seek any order from the California Supreme Court with respect to the
stipulated judgment implementing the settlement agreement between the CPUC and SCE; and the petition did not
request any judicial actions regarding the settlement agreement. The FTCR is not a party to TURN's federal court
appeal concerning the stipulated judgment. On August 14, 2002, the California Supreme Court issued a summary
denial of the FTCR's petition.
Electric Line Maintenance Practices Proceeding
In August 2001, the CPUC issued an order instituting investigation (OII) regarding SCE's overhead and underground
electric line maintenance practices. The OII is based on a report issued by the CPUC's Protection and Safety
Consumer Services Division (CPSD), which alleges SCE had a pattern of noncompliance with the CPUC's General
Orders for the maintenance of electric lines over the period 1998 - 2000. The OII also alleges that noncomplying
conditions were involved in 37 accidents resulting in death, serious injury, or property damage. The CPSD
identified 4,721 alleged violations of the General Orders during the three-year period. The OII placed SCE on
notice that it is potentially subject to a penalty of between $500 and $20,000 for each violation.
Page 6
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Prepared testimony was filed on this matter in April 2002, and hearings were concluded in September 2002. In
opening briefs filed on October 21, 2002, the CPSD recommended SCE be assessed a penalty of $97 million, while
SCE requested that the CPUC dismiss the proceeding and impose no penalties. SCE stated in its opening brief that
it has acted reasonably, allocating its financial and human resources in pursuit of the optimum combination of
employee and public safety, system reliability, cost-effectiveness, and technological advances. SCE also
encouraged the CPUC to transfer consideration of issues related to development of standardized inspection
methodologies and inspector training to an order instituting rulemaking to revise these General Orders opened by
the CPUC in October 2001, or to a new rulemaking proceeding. Reply briefs are due on November 18, 2002, and a
decision is expected by year-end 2002 or early 2003. SCE is unable to predict with certainty whether this matter
ultimately will result in any material financial penalties or impacts on SCE.
Holding Company Proceeding
In April 2001, the CPUC issued an order instituting investigation that reopens the past CPUC decision 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 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. SCE cannot predict with certainty what effects this investigation or any subsequent actions by
the CPUC may have on SCE.
Utility-Retained Generation (URG) Proceeding
On April 4, 2002, the CPUC issued a decision to return URG assets to cost-of-service ratemaking through the end
of 2002. After that time, SCE's URG-related revenue requirement will be determined through the 2003 general rate
case proceeding. Key elements of the URG decision are: retention of the San Onofre incentive pricing mechanism
through 2003; recovery of incurred costs for all URG components other than San Onofre; establishment of an
amortization schedule for SCE's nuclear plants based on their remaining useful lives; and establishment of
balancing accounts for utility generation, purchased power, and Independent System Operator (ISO) ancillary
services.
Based on this decision, during second quarter 2002, SCE reestablished for financial reporting purposes regulatory
assets related to its unamortized nuclear plant, purchased-power settlements and flow-through taxes, reduced the
PROACT balance, and recorded a corresponding credit to earnings of $480 million after tax. The impact of the URG
decision is reflected in the financial statements as a credit (decrease) to the provisions for regulatory clauses
of $644 million, partially offset by an increase in deferred income tax expense of $164 million. The reduction
in the PROACT balance reflects a change in the amortization schedule of SCE's unamortized nuclear facilities from
the schedule required to be used to calculate the PROACT during the last four months of 2001. Implementation of
the URG decision, together with the PROACT mechanism, allowed SCE to reestablish substantially all of the
regulatory assets previously written off to earnings.
Page 7
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Wholesale Electricity Markets
On April 25, 2001, after months of high power prices, the Federal Energy Regulatory Commission (FERC) issued an
order providing for energy price controls during ISO Stage 1 or greater power emergencies (7% or less in reserve
power). The order establishes an hourly clearing price based on the costs of the least efficient generating unit
during the period. Effective June 20, 2001, the FERC expanded the April 25, 2001, order to include non-emergency
periods and price mitigation in the 11-state western region through September 30, 2002. On July 17, 2002, the
FERC issued an order reviewing the ISO's proposals to redesign the market and implementing a market power
mitigation program for the 11-state western region. The FERC declined to extend beyond September 30, 2002, all
of the market mitigation measures it had previously adopted. However, effective October 1, 2002, the FERC
extended a requirement, first ordered in its June 19, 2001, decision, that all western energy sellers offer for
sale all operationally and contractually available energy. It also ordered a cap on bids for real-time energy
and ancillary services of $250/MWh to be effective beginning October 1, 2002, and ordered various other market
power mitigation measures. Implementation of the $250/MWh bid cap and other market power mitigation measures
were delayed until October 31, 2002, by a FERC order issued September 26, 2002. The FERC did not set a specific
expiration date for its new market mitigation plan. SCE cannot yet determine whether the new market mitigation
plan adopted by the FERC will be sufficient to mitigate market price volatility in the wholesale electricity
markets in which SCE will purchase its residual net short electricity requirements (i.e., the amount of energy
needed to serve SCE's customers from sources other than its own generating plants, power purchase contracts and
California Department of Water Resources (CDWR) contracts).
On July 25, 2001, the FERC issued an order that limits potential refunds from alleged overcharges by energy
suppliers to the ISO and California Power Exchange (PX) spot markets during the period from October 2, 2000,
through June 20, 2001, and adopted a refund methodology based on daily spot market gas prices. An administrative
law judge conducted evidentiary hearings on this matter in March, August and October 2002. An initial decision
from the judge is expected by the end of 2002 and a decision by the FERC is expected in 2003. On August 13,
2002, in an investigation proceeding, the FERC's staff issued an initial report on manipulation of electric and
natural gas prices, which identified fundamental flaws in the use of the gas price presently included in the
methodology for calculating refunds. Parties have filed comments on the FERC staff's initial report. SCE cannot
yet determine either the likelihood that the initial report will affect the FERC's determination of refunds or
the 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. SCE has not incorporated any potential refunds into its current
projection of the timing of PROACT recovery.
Note 3. Purchased Power
SCE purchased power through the PX and ISO from April 1998 through mid-January 2001. SCE has bilateral forward
contracts with other entities and power-purchase contracts with other utilities and independent power producers
classified as qualifying facilities (QFs). Purchased power detail is provided below:
Page 8
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
3 Months Ended 9 Months Ended
September 30, September 30,
- --------------------------------------------------------------------------------------------------------------
In millions 2002 2001 2002 2001
- --------------------------------------------------------------------------------------------------------------
(Unaudited)
PX/ISO:
Purchases $ 15 $ 26 $ 79 $ 660
Generation sales -- 2 -- 324
- --------------------------------------------------------------------------------------------------------------
Purchased power - PX/ISO - net 15 24 79 336
Purchased power - bilateral contracts 16 53 46 142
Purchased power - interutility/QF contracts 749 682 1,490 2,812
- --------------------------------------------------------------------------------------------------------------
Total $ 780 $ 759 $ 1,615 $ 3,290
- --------------------------------------------------------------------------------------------------------------
PX/ISO billing adjustments are included in all periods reported above. Net PX/ISO amounts for the three months
ended September 30, 2002, and 2001, and for the nine months ended September 30, 2002, reflect only billing
adjustments. These billing adjustments are recovered through the PROACT and have no impact on earnings. Since
January 17, 2001, all power, other than the QF and bilateral contracts, is purchased by a state agency for
delivery to SCE's customers and is not considered a cost to SCE.
Note 4. 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 course of
business. SCE believes the outcome of these other proceedings will not materially affect its results of
operations or liquidity.
Energy Crisis Issue
In October 2000, a federal class action securities lawsuit was filed against SCE and Edison International. The
lawsuit, as amended, involved securities fraud claims arising from alleged improper accounting for the
energy-cost undercollections. The complaint was supposedly filed on behalf of a class of persons who purchased
Edison International common stock between July 21, 2000, and April 17, 2001. This lawsuit was consolidated with
another similar lawsuit filed on March 15, 2001. SCE and Edison International filed a motion to dismiss the
lawsuits for failure to state a claim and on March 8, 2002, the district court dismissed the complaint with
prejudice. The plaintiffs have dismissed their appeal and on April 26, 2002, the federal court of appeals
dismissed the appeal with prejudice.
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 41 identified sites is $100 million. The ultimate
costs to clean up SCE's identified sites may vary from its recorded liability due to numerous
Page 9
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity
of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting
from investigatory studies; the possibility of identifying additional sites; and the time periods over which site
remediation is expected to occur. SCE believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $285 million. The upper limit of this range of costs
was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes. SCE has
sold all of its gas-fueled generation plants and has retained some liability associated with the divested
properties.
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. Costs incurred at SCE's remaining sites are
expected to be recovered through customer rates. SCE has recorded a regulatory asset of $65 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 $10 million to $25 million. Recorded costs for the twelve months
ended September 30, 2002, were $22 million.
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 (IRS) asserting
deficiencies in federal corporate income taxes for its 1994 to 1996 tax years. The vast majority of the tax
deficiencies are timing differences and, therefore, amounts ultimately paid, if any, would benefit Edison
International as future tax deductions. Edison International is challenging the deficiencies asserted by the
IRS, which are currently under appeal. Edison International believes that it has meritorious legal defenses to
those deficiencies and SCE believes that the ultimate outcome of this matter will not result in a material impact
on SCE's results of operations or financial position.
Navajo Nation Litigation
Peabody Holding Company (Peabody) supplies coal from mines on Navajo Nation lands to the Mohave Generating
Station. In June 1999, the Navajo Nation filed a complaint in federal 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.
Page 10
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
Briefing on this matter has been completed and argument is scheduled for December 2002.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, nor the impact
on this complaint 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 ($200 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 is considering amendments to the applicable federal law that could increase the liability of SCE in case
of a nuclear incident.
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
Page 11
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
through April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee
equal to one mill per kilowatt-hour 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 first quarter of 2005. The spent fuel pool storage capacity for Units 2 and 3 will then
accommodate needs until 2007 for Unit 2 and 2008 for Unit 3. SCE expects to begin using an interim spent fuel
storage facility for Units 2 and 3 spent fuel by early 2006. Palo Verde on-site spent fuel storage capacity will
accommodate needs until 2003 for Unit 2, and until 2004 for Units 1 and 3. Arizona Public Service Company,
operating agent for Palo Verde, expects to begin using an interim spent fuel storage facility by the end of 2002.
Page 12
Item 2. Management's Discussion and Analysis of Results of Operations and
Financial Condition
The Management's Discussion and Analysis of Results of Operations and Financial Condition (MD&A) for the three-
and nine-month periods ended September 30, 2002, discusses material changes in the results of operations,
financial condition and other developments of Southern California Edison Company (SCE) since December 31, 2001,
and as compared to the three- and nine-month periods ended September 30, 2001. This discussion presumes that the
reader has read or has access to SCE's MD&A for the calendar year 2001 (the year-end 2001 MD&A), which was
included in Southern California Edison's 2001 annual report to shareholders and incorporated by reference into
Southern California Edison's Annual Report on Form 10-K for the year ended December 31, 2001.
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 in the Market Risk Exposures and Forward-Looking Information and Risk Factors sections. The
following discussion provides information about material developments since the issuance of the year-end 2001
MD&A and should be read in conjunction with the financial statements contained in this quarterly report and
Southern California Edison's Annual Report on Form 10-K for the year ended December 31, 2001.
This MD&A includes information about SCE, a regulated public utility company providing electricity to retail
customers in central, coastal, and southern California.
RESULTS OF OPERATIONS
Earnings
In 2002, SCE's third quarter and year-to-date earnings were $234 million and $1.1 billion, respectively, compared
to earnings of $651 million and $81 million, respectively, for the three and nine months ended September 30,
2001. The 2002 year-to-date earnings include a $480 million one-time gain in the second quarter to reflect the
implementation of a California Public Utilities Commission (CPUC) decision in SCE's utility-retained generation
(URG) proceeding. In 2001, SCE's third quarter and year-to-date earnings included $518 million and $(205)
million, respectively, in procurement-related adjustments for undercollected power procurement costs. Excluding
these adjustments, SCE's third quarter and year-to-date earnings for the periods ended September 30, 2002, were
$234 million and $595 million, respectively, compared to earnings of $133 million and $287 million, respectively,
for the three and nine months ended September 30, 2001. Excluding these adjustments, the $101 million increase
in SCE's third quarter 2002 earnings and the $308 million increase in year-to-date 2002 earnings primarily
reflects higher revenue from the implementation of the CPUC's April 2002 decisions in SCE's performance-based
ratemaking (PBR) proceeding and URG proceeding and lower interest expense. The increases were partially offset
by higher operating and maintenance expense. The quarterly increase also reflects rewards from SCE's prior
year's performance under its PBR mechanism. The year-to-date increase also reflects increased income from San
Onofre Nuclear Generating Station Units 2 and 3, partially offset by higher depreciation expense. Relevant
regulatory proceedings are discussed below in the PROACT Regulatory Asset, URG Decision and PBR Decision sections.
Accounting principles generally accepted in the United States require SCE, at each financial statement date, to
assess the probability of recovering its regulatory assets through the rate-making process. As of December 31,
2000, SCE was unable to conclude that, under applicable accounting principles, its $4.2 billion generation and
procurement-related regulatory assets were probable of recovery through the rate-making process, and wrote them
off as a charge to earnings in 2000. In the first nine months of 2001, SCE had $205 million (after tax) of power
procurement costs in excess of revenue, which were expensed as incurred.
Page 13
Based on the CPUC's January 23, 2002, resolution regarding the regulatory accounting for PROACT, as of December
31, 2001, SCE was able to conclude that $3.6 billion in regulatory assets previously written off were probable of
recovery through the rate-making process. As a result, SCE's year-ended December 31, 2001, consolidated income
statement included a $2.1 billion credit to earnings. In 2002, any difference between energy procurement costs
and related revenue is accumulated in the PROACT balance. See additional discussion below in the CPUC Litigation
Settlement Agreement section.
Operating Revenue
Approximately 96% 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).
Operating revenue increased for the three and nine months ended September 30, 2002, compared to the same periods
in 2001. The increase for the three months ended September 30, 2002, was primarily due to an increase in overall
sales volume, as well as an increase in revenue resulting from SCE providing its customers with energy from its
own generating plants and power purchase contracts, rather than the California Department of Water Resources
(CDWR) purchasing power on behalf of SCE's customers. Amounts SCE bills to and collects from its customers for
electric power purchased and sold by the CDWR to SCE's customers (beginning January 17, 2001) are being remitted
to the CDWR and are not recognized as revenue by SCE. These amounts were $326 million and $922 million for the
three- and nine-month periods ended September 30, 2002, compared to $642 million and $1.4 billion for the three-
and nine-month periods ended September 30, 2001. The increase in operating revenue was partially offset by a
decrease in revenue arising from an increase in credits given to direct access customers in 2002, compared to
2001, due to a significant increase in the number of direct access customers. The increase for the nine months
ended September 30, 2002, compared to the same period in 2001, was also due to a 3(cent)-per-kWh surcharge authorized
by the CPUC as of March 27, 2001. Although the surcharge was authorized as of March 27, 2001, it was not
collected in rates until the CPUC determined how the rate increase would be allocated among SCE's customer
classes, which occurred in May 2001. To compensate for the two-month delay in collecting the 3(cent)surcharge, the
CPUC authorized an additional $0.006 surcharge for a 12-month period beginning in June 2001, which contributed to
the increase in revenue. Subsequently, the CPUC allowed the continuation of the $0.006 surcharge that was
scheduled to terminate in June 2002 and required SCE to track the associated future revenue in a balancing
account, until the CPUC determines the use of such surcharge. The continuation of the surcharge will result in
an increase to revenue and cash by as much as $200 million in 2002, but will have no impact on earnings (see
Temporary Surcharge). In addition, SCE's revenue was higher due to SCE providing its customers with a greater
volume of energy generated from its own generating plants and power purchase contracts, rather than the CDWR
purchasing on SCE's customers behalf, partially offset by increase in credits given to direct access customers in
2002.
With respect to increase in credits given to direct access customers in the three and nine months ended
September 30, 2002, 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, are invalid. Direct access
arrangements entered into prior to September 20, 2001, remain valid. Most direct access customers continue to be
billed by SCE, but are given a credit for the generation costs SCE saved by not serving them. Operating revenue
is reported net of this credit. See additional discussion on the Direct Access - Historical Procurement Charge
in the Direct Access Proceedings section below.
Operating Expenses
Purchased-power expense decreased significantly for the nine-month period ended September 30, 2002, as compared
to 2001. The decrease resulted primarily from lower expenses at SCE related to qualifying facilities (QFs),
bilateral contracts and interutility contracts, as discussed below. In addition, the decrease reflects the
absence of California Power Exchange (PX)/Independent System Operator (ISO) purchased-
Page 14
power expense after mid-January 2001. See Purchased Power table in Note 3 to the Consolidated Financial
Statements in this quarterly report.
Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated
prices. These contracts expire on various dates through 2025. In 2002, purchased-power expense declined
significantly, primarily due to lower payments to QFs. Generally, energy payments for gas-fired QFs are tied to
spot natural gas prices. Effective May 2002, energy payments for renewable QFs are based on a fixed price.
During the first nine months ended September 30, 2002, spot natural gas prices were significantly lower than the
same periods in 2001. The decrease in 2002 purchased-power expense related to bilateral contracts and
interutility contracts was also due to the decrease in natural gas prices.
PX/ISO purchased-power expense increased significantly between May 2000 and mid-January 2001, due to a number of
factors, including increased demand for electricity in California, dramatic price increases for natural gas (a
key input of electricity production), and problems in the structure and conduct of the PX and ISO markets. In
December 2000, the FERC eliminated the requirement that SCE buy and sell all power through the PX and ISO. Due
to SCE's noncompliance with the PX's tariff requirement for posting collateral for all transactions, as a result
of the downgrades in its credit rating, the PX suspended SCE's market trading privileges effective mid-January
2001. Although SCE has not purchased power from the PX since mid-January 2001, SCE continues to receive
adjusting invoices for power purchased through the PX/ISO prior to mid-January 2001.
Provisions for regulatory adjustment clauses - net increased for both the quarter and year-to-date ended
September 30, 2002, compared to the same periods in 2001. The third quarter increase was primarily due to
overcollections related to the 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 used to reduce the PROACT
balance, as well as revenue collected to recover the rate reduction bond regulatory asset. The year-to-date
increase was primarily due to overcollections used to recover the PROACT balance and revenue collected to recover
the rate reduction bond regulatory asset, partially offset by the impact of SCE's implementation of CPUC
decisions related to URG and the PBR mechanism, as well as the impact of other regulatory actions.
As a result of the URG decision, SCE reestablished regulatory assets previously written off (approximately $1.1
billion) related to its nuclear plant investment, purchased-power settlements and flow through taxes, and
decreased the PROACT balance by $256 million, all retroactive to January 1, 2002. The impact of the URG decision
is reflected in the financial statements as a credit (decrease) to the provisions for regulatory adjustment
clauses of $644 million, partially offset by an increase in deferred income tax expense of $164 million, for a
net credit to earnings of $480 million (see URG Decision discussion). As a result of the CPUC decision that
modified the PBR mechanism, SCE recorded a $136 million credit (increase) to the provisions for regulatory
adjustment clauses in the second quarter of 2002, to reflect undercollections in CPUC-authorized revenue
resulting from changes in retail rates (see PBR Decision discussion).
Other operating and maintenance expense increased for the three-month period ended September 30, 2002, compared
to the same period in 2001, primarily due to the San Onofre Unit 2 refueling outage in 2002, and increases in
transmission and distribution maintenance costs, partially offset by lower expenses related to balancing
accounts.
Depreciation, decommissioning and amortization expense increased for the nine months ended September 30, 2002, as
compared to 2001, 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. A 1994 CPUC
decision allowed SCE to accelerate the recovery of its nuclear-related assets while deferring the recovery of its
distribution-related assets for the same amount. Beginning in January 2002, the CPUC approved the commencement
of recovery of SCE's deferred distribution asset. In addition, the increases reflect amortization expense on the
nuclear regulatory asset reestablished during second quarter 2002 based on the URG decision (discussed below).
Page 15
Other Income and Deductions
Interest and dividend income increased for the three- and nine-month periods ended September 30, 2002, compared
to the same periods in 2001. The increases for both periods were mainly due to the interest earned on the PROACT
balance, partially offset by lower interest income due to a lower average cash balance and lower interest rates
during 2002.
Interest expense - net of amounts capitalized decreased for the three and nine months ended September 30, 2002,
compared to 2001, mainly due to lower short-term debt balances during 2002, as well as lower interest expense
related to the suspension of purchased power in 2001. The decrease was partially offset by an increase in
interest expense related to higher long-term debt expense due to long-term debt balances in 2002.
Other nonoperating deductions decreased for the three- and nine-month periods ended September 30, 2002, as
compared to the respective periods in 2001, primarily due to lower accruals for regulatory matters in 2002.
Income Taxes
Income tax expense decreased for the quarter ended September 30, 2002, and increased for the year-to-date ended
September 30, 2002, as compared to the respective periods in 2001. The quarterly tax expense was lower in 2002,
compared to 2001, as 2001 pre-tax income included recovery of previously undercollected costs. The year-to-date
increase was primarily due to an increase in pre-tax income, partially offset by the reestablishment of
tax-related regulatory assets upon implementation of the URG decision. The year-to-date effective tax rate was
lower than the statutory tax rate due to the reestablishment of tax-related regulatory assets.
FINANCIAL CONDITION
The liquidity of SCE is affected primarily by regulation affecting its ability to recover power purchase and
other costs in retail rates, energy market conditions, debt maturities, access to capital markets, credit
ratings, dividend payments and capital expenditures. Capital resources primarily consist of cash from operations
and external financings.
At September 30, 2002, SCE had drawn on its entire $300 million credit line, which expires March 2004. This
secured line of credit, when available, can be drawn down at bank index rates.
Short-term debt is currently used to finance procurement-related obligations. Long-term debt is used mainly to
finance capital expenditures. External financings are influenced by market conditions and other factors.
California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates. Additionally,
the CPUC regulates SCE's capital structure, which limits the dividends it may pay Edison International by
precluding any dividends that would reduce SCE's equity component of its capital structure below authorized
levels. SCE's settlement agreement with the CPUC also places restrictions on SCE's ability to declare or pay
dividends on its common stock until the earlier of the date SCE's PROACT balance is fully recovered or January 1,
2005, except that if SCE has not recovered all of its procurement-related obligations by December 31, 2003, SCE
may apply to the CPUC for consent to resume common stock dividends prior to January 1, 2005, and the CPUC will
not unreasonably withhold its consent. See additional discussion below in CPUC Litigation Settlement Agreement.
A summary of current liquidity issues is included below. A detailed discussion of liquidity issues is included
in the Financial Condition (pages 6 and 7) disclosure in the year-end 2001 MD&A.
Page 16
Liquidity Issues
Sustained high wholesale energy prices from May 2000 through June 2001 and a freeze on retail rates resulted in
significant undercollections of wholesale power costs. These undercollections, coupled with SCE's anticipated
near-term capital requirements and the adverse reaction of the credit markets to continued regulatory uncertainty
regarding SCE's ability to recover its current and future power procurement costs, materially and adversely
affected SCE's liquidity throughout 2001. As a result of its liquidity concerns, beginning in January 2001, SCE
suspended payments for purchased power, deferred payments on outstanding debt, and did not declare or pay
dividends on any of its cumulative preferred stock or common stock.
In January 2002, the CPUC adopted a resolution implementing a settlement agreement with SCE. Based on the rights
to power procurement cost recovery and revenue established by the agreement and the PROACT resolution, SCE repaid
its undisputed past-due obligations and near-term debt maturities in March 2002, using cash on hand resulting
from rate increases approved by the CPUC in 2001, and the proceeds of $1.6 billion in senior secured credit
facilities and the remarketing of $196 million in pollution-control bonds. The $1.6 billion financing included a
$600 million, one-year term loan, due on March 3, 2003. SCE prepaid $300 million of this loan on August 14, 2002.
At September 30, 2002, SCE had cash of $1.3 billion. SCE expects to meet its continuing obligations in 2002 from
cash on hand and operating cash flows. Material factors affecting the timing of recovery of the PROACT balance
are discussed below in PROACT Regulatory Asset. In 2003, SCE's significant debt maturities are approximately
$1.7 billion, comprising of $1 billion in variable rate notes due November 2003, the remaining $300 million ($300
million was prepaid in August 2002) of a one-year term loan due March 2003, $125 million in first and refunding
mortgage bonds due June 2003 and approximately $250 million of rate reduction notes due throughout 2003. After
2002, SCE's liquidity may be affected by, among other things, matters described in the CPUC Litigation Settlement
Agreement, the CDWR Revenue Requirement Proceeding and the Generation Procurement Proceeding sections. The CPUC
has ordered SCE to resume procurement of its residual net short on January 1, 2003. SCE expects to post
collateral to secure its obligations under power purchase contracts and to transact through the ISO for imbalance
power. See the discussion of SCE under Market Risk Exposures below.
Cash Flows from Operating Activities
Net cash provided by operating activities for the nine months ended September 30, 2002, was $259 million,
compared to net cash provided by operating activities of $2.3 billion for the nine months ended September 30,
2001. In 2002, net cash provided by operating activities was primarily due to overcollections mainly resulting
from the CPUC-approved surcharges (1(cent)per kWh in January 2001, 3(cent) per kWh in June 2001 and a temporary $0.006 per
kWh in June 2001), partially offset by SCE's March 2002 repayment of past-due obligations, mainly related to
purchased power. In 2001, cash provided by operating activities was primarily affected by SCE temporarily
suspending payments for purchased power and other obligations beginning in January 2001.
Cash Flows from Financing Activities
Net cash used by financing activities was $1.7 billion for the nine months ended September 30, 2002, compared to
net cash provided by financing activities of $361 million for the nine months ended September 30, 2002. In 2002,
cash used by financing activities was primarily due to SCE's March 2002 payments of $1.65 billion of credit
facilities and $531 million of matured commercial paper, as well as long-term debt repayments. These payments
were partially offset by the closing of a $1.6 billion financing and the remarketing of $196 million in
pollution-control bonds that took place in the first quarter of 2002. The $1.6 billion financing that took place
in the first quarter of 2002 included a $600 million, one-year term loan, due on March 3, 2003. SCE prepaid $300
million of this loan on August 14, 2002.
In 2001, net cash provided by financing activities was primarily due to SCE borrowing additional amounts to
finance general cash requirements, partially offset by the January 2001 repurchase of $420 million of
pollution-control bonds that could not be remarketed in accordance with their terms.
Page 17
Cash Flows from Investing Activities
Cash flows from investing activities are affected by additions to property and plant and funding of nuclear
decommissioning trusts.
COMMITMENTS
SCE's long-term debt maturities and sinking fund requirements for the five twelve-month periods following
September 30, 2002, are: 2003 - $872 million; 2004 - $1.7 billion; 2005 - $1.1 billion; 2006 - $447 million; and
2007 - $247 million. These amounts have been updated to reflect the $1.6 billion in debt SCE issued on March 1,
2002.
Preferred stock redemption requirements for the five twelve-month periods following September 30, 2002, are
$9 million for each period 2003 through 2007.
MARKET RISK EXPOSURES
SCE's primary market-risk exposures include commodity-price risk and interest rate-risk that could adversely
affect results of operations or financial position. Commodity price risk arises from fluctuations in the market
price of electricity, natural gas, or coal. Interest rate risk arises from fluctuations in interest rates.
Additionally, natural gas is a key input for the prices specified in a portion of SCE's QF (including non-gas QF)
contracts. Virtually all of SCE's exposure to changes in the spot market price for natural gas through 2003 is
hedged through financial derivatives or fixed-price contracts. SCE's risk-management policy allows the use of
derivative financial instruments to manage its financial exposures, but prohibits the use of these instruments
for speculative or trading purposes.
Under the CPUC settlement agreement, SCE is permitted full recovery of its power procurement costs during the
PROACT recovery period. After the PROACT recovery period, SCE expects to recover its 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 revenues collected for the CDWR. As a result of these regulatory mechanisms, the effects of
market risks, if any, will impact SCE's cash flows but are not expected to have an impact on earnings.
On October 24, 2002, a CPUC decision was issued that ordered SCE to resume 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) beginning January 1, 2003, and approved SCE's procurement plan filed with
the CPUC, subject to certain modifications. SCE plans to enter into capacity contracts of up to 5 years in order
to reduce its exposure to spot market prices for power. In addition, SCE expects that it will transact through
the ISO for imbalance power. SCE will be required to post collateral to support its obligations under either of
these types of transactions.
The reduction in the credit quality of many trading parties increases SCE's credit risk. In the event a
counterparty were to default on its obligations, SCE also would be exposed to potentially higher costs for
replacement power. SCE has developed standards that limit extension of unsecured credit based upon a number of
objective factors. In negotiating capacity contracts, SCE also has included collateral requirements and credit
enforcements to mitigate the risk of possible defaults. However, these actions may not protect SCE in the event
of bankruptcy of a counterparty.
SCE forecasts that its average 2003 residual net short, on an energy basis, will be approximately 5% 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 is 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
Page 18
are allocated to SCE's customers. Factors that could cause SCE's residual net short to be larger than expected
include: direct access customers returning to utility service from their energy service provider; lower utility
generation; lower deliveries under QF, CDWR or interutility contracts; or higher load requirements.
On July 17, 2002, the FERC issued an order implementing a market power mitigation program for the 11-state
western region. SCE cannot yet determine whether the new market mitigation plan adopted by the FERC will be
sufficient to mitigate market price volatility in the wholesale electricity markets in which SCE will be
purchasing its residual net short electricity requirements.
During 2000 and 2001, SCE experienced severe cost volatility associated with its QF contracts. To mitigate this
volatility, SCE purchased $209 million in hedging instruments (gas call options) in October and November 2001 to
hedge a majority of its natural gas price exposure associated with QF contracts for 2002 and 2003. Although the
gas call options are reflected in the income statement, any fair value changes of the gas call options are offset
through a regulatory balancing account; therefore, fair value changes do not affect earnings. On March 13, 2002,
SCE filed an application with the CPUC for approval and recovery of $209 million in hedging costs. No party is
challenging the reasonableness of SCE's expenditure. In addition, most renewable QFs are paid a fixed price of
5.37(cent)per kWh for energy.
See additional discussion on these matters in CPUC Litigation Settlement Agreement, Generation Procurement
Proceeding and Wholesale Electricity Markets below.
REGULATORY MATTERS
Generation and Power Procurement
CPUC Litigation Settlement Agreement
In October 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. 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 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 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. Specifically, the appeals court affirmed the district court in the following respects: (1) the
district court did not err in denying the motions to intervene brought by entities other than TURN; (2) the
district court did not err in denying standing for the entities other than TURN to appeal the stipulated
judgment; (3) the district court was not deprived of original jurisdiction over the lawsuit; (4) the district
court did not err in declining to abstain from the case; (5) the district court did not exceed its authority by
approving the stipulated judgment without TURN's consent; (6) the district court's approval of the settlement
agreement did not deny TURN due process; and (7) the district court did not violate the Tenth Amendment of the
United States Constitution in approving the stipulated judgment. 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
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certifying those issues to the California Supreme Court and requested that the California Supreme Court accept
certification.
The appeals court stayed further proceedings in the case pending a response from the California Supreme Court on
the request for certification. The appeals court did not stay the continued operation of the settlement
agreement, thus collection of past procurement costs under PROACT is continuing. On October 29, 2002, SCE filed
a brief requesting that the California Supreme Court answer the appeals' court certification and requesting that
the hearing of the matter be placed on the California Supreme Court's March 2003 calendar, or heard at the
court's earliest convenience. 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.
The provisions of the settlement agreement are described in the CPUC Litigation Settlement Agreement disclosure
in the year-end 2001 MD&A (pages 10 and 11).
In April 2002, the Foundation for Taxpayer and Consumer Rights (FTCR), an advocacy group, filed a petition in the
California Supreme Court against the CPUC. The FTCR's petition asserted that, among other things, the CPUC
exceeded its authority and violated state law in approving the settlement agreement and stipulated judgment with
SCE. The petition sought a declaration that the CPUC cannot agree not to enforce any state law unless an
appellate court has determined that the state law is invalid, unconstitutional, or unenforceable. The FTCR's
petition expressly stated that it did not seek any order from the California Supreme Court with respect to the
stipulated judgment implementing the settlement agreement between the CPUC and SCE; and the petition did not
request any judicial actions regarding the settlement agreement. The FTCR is not a party to TURN's federal court
appeal concerning the stipulated judgment. On August 14, 2002, the California Supreme Court issued a summary
denial of the FTCR's petition.
PROACT Regulatory Asset
In accordance with the settlement agreement and an implementing resolution adopted by the CPUC, SCE established a
regulatory balancing account called the PROACT 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 was $2.6
billion at December 31, 2001, and $905 million on September 30, 2002. SCE has previously projected that it will
recover the remaining balance of the procurement-related obligations in the PROACT by the end of 2003. SCE still
believes this projection is appropriate, however, there are many important proceedings pending before the CPUC,
which depending upon decisions made, could cause the balance to be recovered by mid-2003. Material factors that
would change SCE's estimate of the timing of PROACT recovery are:
o the level of output of SCE's generating plants and contract power deliveries (for example, higher than
forecasted output accelerates PROACT recovery);
o authorized revenue changes for distribution, transmission, and SCE retained-generation costs (see
discussion in GRC, PBR and URG Proceedings);
o outcome of issues currently being addressed in the Generation Procurement Proceeding, including the
allocation among the California utilities of power contracted by the CDWR and the related CDWR revenue
requirement impacts;
o SCE's share of the CDWR revenue requirement (see discussion in CDWR Revenue Requirement Proceeding);
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o disposition of the $0.006 temporary surcharge revenue (see discussion in Temporary Surcharge);
o level of retail sales (for example, higher than forecasted sales would accelerate PROACT recovery);
o level of direct access (see Direct Access discussions below);
o direct access customers' contribution to recovery of SCE's PROACT-related costs and to the CDWR's costs
(see Direct Access discussions regarding the historical procurement charge and exit fees below);
o a decision by the CPUC to allow SCE to recover $209 million used to hedge gas price risk associated with
QF contracts (which has been incorporated into SCE's current projection of the timing of PROACT
recovery; see discussion in Market Risk Exposures);
o a decision by the CPUC, which could be made under the Settlement Agreement, directing $150 million of
surplus revenue in both 2002 and 2003 to be used for any utility purpose (which would delay PROACT
recovery); and
o potential energy supplier refunds (see discussion in Wholesale Electricity Markets).
The following is an update on various regulatory proceedings impacting the timing of PROACT recovery:
Direct Access Proceedings
Direct Access - Historical Procurement Charge. From 1998 through mid-September 2001, SCE's customers were able
to choose to purchase power directly from an energy service provider other than SCE (thus becoming direct access
customers) or continue to purchase power from SCE. (Customers who continue to purchase power from SCE are
referred to as bundled service customers). On March 21, 2002, the CPUC issued a final decision affirming that
new direct access arrangements entered into by SCE's customers after September 20, 2001, are invalid. This
decision did not affect direct access arrangements in place before that date. Direct access customers receive a
credit for the generation costs SCE saves by not serving them. Electric utility revenue is reported net of this
credit. Because of this credit, direct access power purchases resulted in additional undercollected power
procurement costs to SCE during 2000 and 2001. On July 17, 2002, the CPUC issued an interim decision to
establish a nonbypassable historical procurement charge requiring direct access customers to pay $391 million of
SCE's past power procurement costs, and directed SCE to reduce the PROACT balance by $391 million and create a
new regulatory asset for the same amount. 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 issues and implements 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 is implemented, the contribution by direct
access customers to the historical procurement charge would be reduced from 2.7(cent)per kWh to 1(cent)per kWh until the
$391 million is collected, with the remainder of the 2.7(cent)per kWh utilized for other 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. Once the interim decision becomes permanent, SCE will evaluate whether a new regulatory asset
could be created. If such a regulatory asset is created, the net effect of this action would be to accelerate
PROACT recovery.
Direct Access - Exit Fees. In addition to the historical procurement charge, the CPUC, in a November 7, 2002,
decision, assigned 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 is in the process of selling approximately
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$12 billion in bonds to repay the amounts it borrowed to pay these costs. The CPUC decision stated that the
direct access customers are responsible for payment of the 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, rather than July 1, 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 should 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 URG
(e.g., qualifying facilities contract costs) that pursuant to AB 1890 are to be recovered from all customers on
an ongoing basis. The CPUC decision states that: (1) the bond charge is applicable to all direct access customers
except those that 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. The exact amount of exit fees associated with the CPUC's decision will be
addressed in workshops to be convened by the CPUC and implemented following the workshops.
The impact of the November 7, 2002, decision is incorporated into SCE's current projection of the timing of
PROACT recovery.
Surcharge Decision
A March 2001, CPUC decision authorized SCE a 3(cent)surcharge and made permanent a 1(cent)temporary surcharge authorized
in January 2001, with the restriction that the revenue arising from both surcharges apply only to ongoing
procurement charges and future power purchases. On November 7, 2002, the CPUC issued a decision modifying the
March 2001 decision to allow the surcharge revenue to be used not only for power costs but also for returning SCE
to reasonable financial health. The decision stated that the extent to which the surcharge revenue could be used
for future power costs or obtaining reasonable financial health would be the subject of future proceedings. The
decision ordered SCE to continue tracking surcharge revenue in balancing accounts, as they remain subject to
later adjustment and possible refund. This decision is incorporated into SCE's current projection of the timing
of PROACT recovery.
Temporary Surcharge
As discussed in Operating Revenue, the CPUC allowed the continuation of the $0.006 surcharge that was scheduled
to terminate in June 2002 and required SCE to track the associated revenue in a balancing account, until the CPUC
determines the use of the surcharge. The continuation of the surcharge will result in an increase to revenue and
cash by as much as $200 million in 2002 and $350 million in 2003, but will have no impact on earnings. SCE has
filed testimony in the CDWR Revenue Requirement phase of the Rate Stabilization Proceeding proposing that this
increase in revenue be used to partially offset the CDWR's higher 2003 revenue requirement, and has incorporated
that assumption into its current projection of the timing of PROACT recovery.
URG Decision
On April 4, 2002, the CPUC issued a decision to return generation assets retained by SCE (utility-retained
generation) to cost-of-service ratemaking until the implementation of the 2003 general rate case (GRC) proceeding
described below. The URG decision:
o Allows recovery of incurred costs for all URG components other than San Onofre Units 2 and 3, subject to
reasonableness review by the CPUC;
Page 22
o Retains the incremental cost incentive pricing mechanism (ICIP) for San Onofre Units 2 and 3 through 2003;
o Establishes an amortization schedule for SCE's nuclear facilities that reflects their current remaining
Nuclear Regulatory Commission license durations, using unamortized balances as of January 1, 2001, as a
starting point;
o Establishes balancing accounts for the costs of utility generation, purchased power, and ancillary
services from the ISO; and
o Continues the use of SCE's last CPUC-authorized return on common equity of 11.6% for SCE's URG rate base
other than San Onofre Units 2 and 3, and keeps in place the 7.35% return on rate base for San Onofre
Units 2 and 3 under the ICIP.
Based on this decision, during the second quarter of 2002, SCE reestablished for financial reporting purposes
regulatory assets related to its unamortized nuclear facilities, purchased-power settlements and flow-through
taxes, reduced the PROACT regulatory asset balance (by $256 million), and recorded a corresponding credit to
earnings of $480 million after tax. The reduction in the PROACT balance reflects a change in SCE's unamortized
nuclear facilities amortization schedule to reflect a ten-year amortization period rather than a four-year
amortization period, which was used to calculate the PROACT, for ratemaking purposes, during the last four months
of 2001. Implementation of the URG decision, together with the PROACT mechanism, allowed SCE to reestablish
substantially all of the regulatory assets previously written off to earnings.
CDWR Revenue Requirement Proceeding
On August 16, 2002, the CDWR issued an updated revenue requirement of $5.8 billion for calendar year 2003, for
its bond costs and power procurement costs. On November 8, 2002, however, the CDWR informed the CPUC that it was
lowering the bond-related portion of its annual revenue requirement from $1.14 billion to approximately $745
million. As a result, its total 2003 revenue requirement is now approximately $5.4 billion.
In a decision dated September 19, 2002, the CPUC allocated the CDWR's entire portfolio of long-term contracts
among the three investor-owned utilities (further discussed in Generation Procurement Proceeding). While the
variable costs of the contracts were also allocated to follow the contracts in that decision, allocation of the
fixed costs for the contracts was delegated to the CDWR Revenue Requirement Proceeding.
In its February 21, 2002, decision allocating the CDWR's 2001-2002 revenue requirement, the CPUC assigned $3.5
billion (38.2%) of the CDWR's total revenue requirement of $9 billion to SCE. This resulted in an average annual
CDWR revenue requirement of $1.7 billion being allocated to SCE. Based on the August 16, 2002, revised 2003 CDWR
revenue requirement, the modified bond charge revenue requirement and the CPUC's allocation of the CDWR contracts
and total contract costs, SCE's share of the CDWR's 2003 revenue requirement is estimated to be approximately
$2.2 billion. This amount consists of approximately 40% of the CDWR's power charge revenue requirement of $4.7
billion and approximately 45% of the CDWR's bond charge revenue requirement of $745 million. Therefore, SCE's
share of the total CDWR's 2003 revenue requirement is expected to be about $450 million higher than SCE's share
of the average annual 2001-2002 CDWR revenue requirement. This amount is incorporated into SCE's current
projection of the timing of PROACT recovery. A larger allocation would delay PROACT recovery.
In its February 21, 2002, decision, the CPUC ordered that allocation of that revenue requirement to each utility
be trued-up based on the CDWR's actual recorded costs for the 2001-2002 period and a specific methodology set
forth in that decision. The presiding administrative law judge in the Rate Stabilization Proceeding has issued a
preliminary ruling deferring the true-up of the CDWR's 2001-2002 revenue requirement and its allocation to the
utilities to the second quarter of 2003 when all of the CDWR's 2002
Page 23
recorded expenses will be available. SCE has filed a brief opposing deferral of the true-up of the CDWR's
2001-2002 revenue requirement to the second quarter of 2003 on the grounds that the true-up should be performed
based on the available data at this time and be used to adjust the utilities' allocation of the CDWR's 2003
revenue requirement. A true-up of the CDWR's revenue requirement has not been incorporated into SCE's current
projection of the timing of PROACT recovery.
On October 24, 2002, the CPUC issued a decision which adopts a methodology for establishing a charge to repay
bond-related costs resulting from the CDWR's bond sale to refinance an interim loan taken to cover electricity
costs and to repay advances from the State's General Fund used to pay its procurement costs over the first nine
months of 2001. The bond charge is to be set by dividing the annual revenue requirement for bond-related costs
by an estimate of the annual electricity consumption of bundled service customers subject to the charge. The
charge will apply to electricity consumed on and after November 15, 2002. In a November 7, 2002, decision, the
CPUC assigned responsibility for a portion of the bond charge to direct access customers. (see Direct Access -
Exit Fees). This decision is incorporated into SCE's current projection of the timing of PROACT recovery.
Generation Procurement Proceeding
In October 2001, the CPUC issued an order instituting rulemaking (OIR) directing SCE and the other major
California electric utilities to provide recommendations for establishing policies and mechanisms to enable the
utilities to resume power procurement by January 1, 2003.
SCE filed testimony on May 1, 2002, that proposed specific elements of a broad procurement framework including
processes to assure full, certain and timely recovery of reasonable procurement costs, and clear guidelines and
pre-approvals, when appropriate, instead of after-the-fact reasonableness reviews. The testimony also set forth
a detailed plan for SCE resuming procurement beginning in 2003 that focused on how to best serve the load
requirements of its bundled retail customers that is not met by SCE's existing generation supply and SCE's
allocated share of the CDWR contracts.
SCE also requested approval by the CPUC of a proposed interim procedure allowing SCE to enter into new contracts
for capacity products jointly with the CDWR prior to January 1, 2003.
On August 22, 2002, the CPUC issued a decision authorizing the utilities to enter capacity contracts between the
effective date of the decision and January 1, 2003, referred to as the transition procurement period. The CPUC
must approve or disapprove the transitional contracts or procurement process proposed by a utility by means of an
expedited advice letter process. Costs incurred under these CPUC-approved contracts will be considered
reasonable and prudent for cost recovery. The decision also requires the utilities to procure, during this
transition procurement period, at least one percent of their annual electricity sales through a set-aside
competitive procurement process for renewable resources.
Pursuant to the authority to enter into transitional procurement contracts, SCE initiated a request for offers
from a large number of suppliers for various capacity and energy products. SCE negotiated transactions with
several suppliers and has submitted an advice letter to the CPUC on November 5, 2002, requesting review and
approval of these transactions. A decision is expected to be made at the CPUC meeting on December 5, 2002. If
the CPUC approves these capacity contracts, SCE will then enter into further negotiations with these suppliers to
finalize pricing and quantity, and SCE will, if the final pricing and quantity terms are acceptable, execute some
or all of the contracts.
The OIR proceeding also addressed the issue of allocating the contracts previously entered into by the CDWR among
the three major California utilities. A decision setting the allocation of the CDWR contracts among the three
utilities was issued on September 19, 2002. The decision allocated the contracts on a contract-by-contract
basis. The decision significantly reduces SCE's residual net short and also increases the likelihood that SCE
will have excess power during certain periods, particularly after 2003. Revenue from the sale of such surplus
energy is to be prorated between the CDWR contracts (to be credited to the CDWR's revenue requirement) and the
other resources in the utility's portfolio. Under the decision, utility responsibility for the contracts is
limited to that of scheduling and dispatch. SCE is attempting to negotiate
Page 24
with the CDWR the terms under which this responsibility will be carried out. Legal title, financial reporting
and responsibility for the payment of contract-related bills remains with the CDWR. As such, a portion of the
revenue from surplus energy sales, as well as all of the expense for power purchased under the CDWR allocated
contracts will not be recognized as revenue or purchased power expense by SCE. The cost allocation among the
utilities of the CDWR revenue requirement, which is composed in large part of contract costs, is to be determined
in a separate proceeding (see CDWR Revenue Requirement Proceeding above).
AB 57, which provides for SCE and the other California utilities to resume procuring power for their customers
was signed into law by the Governor of California in September 2002. A second bill, SB 1976, was enacted not
long after AB 57 to shorten the time period between adoption and the implementation of a utility's procurement
plan from 90 to 60 days. Collectively, AB 57 and SB 1976 provide that a procurement plan approved for a utility
by the CPUC should, among other things: (a) enable the utility to fulfill its obligation to serve its customers
at just and reasonable rates; (b) eliminate the need for after-the-fact reasonableness reviews of the utility's
actions in compliance with the plan; (c) ensure timely recovery of costs incurred under the plan; and
(d) moderate the price risk to the utility of serving its retail customers. In addition, AB 57 provides that the
CPUC shall not approve a feature or mechanism in a utility's procurement plan if the CPUC finds that it would
impair the restoration of, or lead to a deterioration of, the utility's creditworthiness.
On October 24, 2002, the CPUC issued a decision ordering the utilities to resume procurement and adopting the
regulatory framework under which the utilities shall resume full procurement responsibilities on January 1,
2003. The decision distinguishes the utilities' responsibilities on the basis of short-term (2003) versus
long-term (2004-2024) procurement. It adopts the utilities' procurement plans filed on May 1, 2002, and directs
that they be modified prior to January 1, 2003, to reflect the decision, the allocation of existing CDWR
contracts, and any procurement done under the August 26, 2002, decision. The October 24, 2002, decision also
sets forth a detailed process and procedural schedule to develop long-term procurement planning that includes the
filing by each utility of a long-term plan by April 1, 2003, and an evidentiary hearing in early July 2003. In
addition, the decision calls for each of the utilities to establish a balancing account, to be known as the
energy resource recovery account, to track energy costs. These balancing accounts will be used for examining
procurement rate adjustments on a semi-annual basis, as well as on a more expedited basis in the event fuel and
purchased-power costs exceed a prescribed threshold. SCE believes there are a number of important issues in the
decision that must be clarified by the CPUC in order to have a procurement framework consistent with AB 57. In
particular, the decision language regarding reasonableness of utility actions is vague in a number of respects,
and could expose SCE to after-the-fact reasonableness review. Moreover, there is no time frame for the CPUC to
complete these reasonableness reviews. Although the decision adopts the procurement plan SCE submitted in May
2002, it is not clear whether SCE has the authority to begin procuring before late December 2002. SCE intends to
seek rehearing of this decision and will ask for clarification in future filings.
On November 12, SCE filed its modified short-term procurement plan pursuant to the CPUC's October 24, 2002,
decision. SCE's modified plan updates its May filing in several respects including the final allocation of the
CDWR power contracts, SCE's renewable generation solicitation, revised residual net short estimates, and
potential collateral requirements. SCE's modified plan also seeks clarification of the CPUC's procurement
oversight framework. In particular, SCE's plan reflects the following views: the CPUC must exercise its
oversight authority over the entire resource portfolio in a manner consistent with AB 57; the CPUC must eliminate
after-the-fact reasonableness reviews for all actions taken in compliance with a CPUC-approved procurement plan;
to the extent deficiencies are discovered in an approved plan, the CPUC must make adjustments prospectively only;
for actions not in compliance with the plan, disallowances should be levied only based on clear and convincing
evidence that the actions were outside a range of reasonable managerial conduct and had a net detrimental effect
on customers; the burden of presenting clear and convincing proof that management has acted unreasonably should
rest with the party making such allegations; and finally, SCE's modified plan seeks a limitation on possible
disallowances to no more than its annual cost of administering the procurement function, except in cases of
fraud, willful misconduct, gross negligence or self dealing.
Page 25
Mohave Generating Station Application
On May 17, 2002, SCE filed with the CPUC an application to address the future disposition of SCE's share of the
Mohave Generating Station (Mohave). Mohave obtains all of its coal supply from a mine in northeast Arizona on
lands of the Navajo Nation and Hopi Tribe (the Tribes). This coal is delivered from the mine to Mohave by means
of a coal slurry pipeline, which requires water that is obtained from groundwater wells located on lands of the
Tribes in the mine vicinity.
Due to the lack of progress in negotiations with the Tribes and other parties to resolve several coal and water
supply issues, SCE's application states that it appears that it probably will not be possible for SCE to extend
Mohave's operation beyond 2005. Uncertainty over a post-2005 coal supply has also prevented SCE and the other
Mohave co-owners from starting to install extensive pollution control equipment that must be put in place if
Mohave's operations are extended past 2005.
SCE intends to continue to participate in discussions to resolve the coal supply and slurry-water supply issues.
SCE's application states that if SCE obtains adequate assurance by the end of 2002 that these issues will be
satisfactorily resolved, it will seek CPUC authorization for making the necessary pollution control expenditures
and certain other investments upon determination that such expenditures are economic and in SCE's customer's
interest. Because SCE expects that CPUC action on such a request could take a year or more, SCE's May 17, 2002,
application requests either: a) pre-approval for SCE to immediately begin spending up to $58 million on Mohave
pollution controls in 2003, if by year-end 2002, SCE has obtained adequate assurance the outstanding coal and
slurry-water issues can be satisfactorily resolved; or b) authority for SCE to establish certain balancing
accounts and otherwise begin preparing to terminate Mohave's coal-fired operations at the end of 2005.
Several parties filed protests or responses to SCE's application. Some of these support, at least in part,
authorization for the interim funding to extend Mohave's operation, but none of them provide, in SCE's view,
solutions to the coal and slurry-water issues that must be resolved for Mohave to be reasonably assured of a
post-2005 coal supply. The CPUC administrative law judge has ordered all parties in the proceeding to file, by
November 21, 2002, an all-party joint statement with an updated summary of the facts and issues associated with
SCE's application. SCE continues to request a decision on interim funding by the end of 2002.
For additional matters related to the Mohave Generating Station see the Navajo Nation Litigation discussion under
the Other Developments section.
The outcome of SCE's application is not expected to impact Mohave's operation through 2005. Consequently, this
matter has no impact on the timing of PROACT recovery.
Transmission and Distribution
PBR Decision
SCE's revenue related to distribution operations is determined through a PBR mechanism. The distribution PBR
mechanism was to have ended in December 2001, but in June 2001 the CPUC extended the mechanism until SCE's next
GRC, which is expected to be effective in 2003. On April 22, 2002, the CPUC issued a decision that modifies the
PBR mechanism in the following significant respects:
o SCE's current PBR distribution sales mechanism is converted to a revenue requirement mechanism to
prevent material revenue undercollections or overcollections resulting from changes in retail rates. A
balancing account will be established to record any undercollections or overcollections. This is
retroactively effective as of June 14, 2001. SCE established this balancing account as of the date of
the decision.
o A methodology is adopted for setting SCE's distribution revenue requirement for June 14 to December 31,
2001, calendar year 2002, and calendar year 2003 until replaced
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by the GRC. The methodology (a) establishes 2000 as the base year, (b) annually adjusts SCE's distribution revenue
requirement by the change in the Consumer Price Index minus a productivity factor of 1.6%, and
(c) annually increases SCE's distribution revenue requirement to account for additional costs of
expanding the distribution network to connect new customers (an allowance of about $650 per customer).
o The performance benchmarks for worker safety, customer satisfaction, and outage frequency are updated
beginning in 2002 to reflect improvements in SCE's performance. These changes will reduce rewards SCE
would earn compared to the previous standards.
As a result of this decision, SCE recorded credits to earnings of approximately $26 million for revenue
undercollections during the period June 14, 2001, through December 31, 2001, and has recorded credits to earnings
of $79 million for the nine-month period ended September 30, 2002. SCE projects additional credits to earnings
for revenue undercollections of approximately $30 million for the remainder of 2002. All of these amounts are on
an after-tax basis. This decision is incorporated into SCE's current projection of the timing of PROACT recovery.
CPUC GRC Proceeding
In December 2001, SCE submitted a notice of intent to file its 2003 GRC with the CPUC, requesting an increase of
approximately $500 million in revenue (compared to 2000 recorded revenue) for its distribution and generation
operations. On May 3, 2002, SCE filed its formal application for the 2003 GRC. After taking into account the
effects of the CPUC's April 22, 2002, PBR decision, SCE reduced the revenue increase requested in the application
to $286 million. The requested revenue increase is primarily related to capital additions 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. Hearings are now scheduled to begin in
November 2002. A final decision is expected in the third quarter of 2003. SCE's requested revenue increase has
been incorporated into the current projection of the timing of PROACT recovery.
Cost of Capital Decision
On November 7, 2002, the CPUC issued a decision in SCE's cost of capital proceeding, adopting an 11.6% return on
common equity for 2003 for SCE's CPUC jurisdictional assets. This decision is incorporated into SCE's current
projection of the timing of PROACT recovery.
Electric Line Maintenance Practices Proceeding
In August 2001, the CPUC issued an order instituting investigation (OII) regarding SCE's overhead and underground
electric line maintenance practices. The OII is based on a report issued by the CPUC's Protection and Safety
Consumer Services Division (CPSD), which alleges SCE had a pattern of noncompliance with the CPUC's General
Orders for the maintenance of electric lines over the period 1998 - 2000. The OII also alleges that noncomplying
conditions were involved in 37 accidents resulting in death, serious injury, or property damage. The CPSD
identified 4,721 alleged violations of the General Orders during the three-year period. The OII placed SCE on
notice that it is potentially subject to a penalty of between $500 and $20,000 for each violation.
Prepared testimony was filed on this matter in April 2002, and hearings were concluded in September 2002. In
opening briefs filed on October 21, 2002, the CPSD recommended SCE be assessed a penalty of $97 million, while
SCE requested that the CPUC dismiss the proceeding and impose no penalties. SCE stated in its opening brief that
it has acted reasonably, allocating its financial and human resources in pursuit of the optimum combination of
employee and public safety, system reliability, cost-effectiveness, and technological advances. SCE also
encouraged the CPUC to transfer consideration of issues related to development of standardized inspection
methodologies and inspector training to an order instituting rulemaking to revise these General Orders opened by
the CPUC in October 2001, or to a new rulemaking proceeding. Reply briefs are due on November 18, 2002, and a
decision is expected by year-end 2002 or
Page 27
early 2003. SCE is unable to predict with certainty whether this matter ultimately will result in any material
financial penalties or impacts on SCE.
Wholesale Electricity Markets
On July 25, 2001, the FERC issued an order that limits potential refunds from alleged overcharges by energy
suppliers to the ISO and PX spot markets to sales during the period from October 2, 2000, through June 20, 2001,
and adopted a refund methodology based on daily spot market gas prices. An administrative law judge conducted
evidentiary hearings on this matter in March, August and October 2002. An initial decision from the judge is
expected by the end of 2002 and a decision by the FERC is expected in 2003. On August 13, 2002, in an
investigation proceeding, the FERC's staff issued an initial report on manipulation of electric and natural gas
prices, which identified fundamental flaws in the use of the gas price presently included in the methodology for
calculating refunds. Parties have filed comments on the FERC's staff's initial report. SCE cannot yet determine
the likelihood that the initial report will affect either the timing of the FERC's determination of refunds or
the 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. SCE has not incorporated any potential refunds into its current
projection of the timing of PROACT recovery.
On July 17, 2002, the FERC issued an order reviewing the ISO's proposals to redesign the market and implementing
a market power mitigation program for the 11-state western region. The FERC declined to extend beyond September
30, 2002, all of the market mitigation measures it had previously adopted. However, effective October 1, 2002,
the FERC extended a requirement, first ordered in its June 19, 2001, decision, that all western energy sellers
offer for sale all operationally and contractually available energy. It also ordered a cap on bids for real-time
energy and ancillary services of $250/MWh to be effective beginning October 1, 2002, and ordered various other
market power mitigation measures. Implementation of the $250/MWh bid cap and other market power mitigation
measures were delayed until October 31, 2002, by a FERC order issued September 26, 2002. The FERC did not set a
specific expiration date for its new market mitigation plan. SCE cannot yet determine whether the new market
mitigation plan adopted by the FERC will be sufficient to mitigate market price volatility in the wholesale
electricity markets in which SCE will be purchasing its residual net short electricity requirements.
Holding Company Proceeding
In April 2001, the CPUC issued an order instituting investigation that reopens the past CPUC decision 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 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. SCE cannot predict with certainty what effects this investigation or any subsequent actions by
the CPUC may have on SCE.
Page 28
OTHER DEVELOPMENTS
Environmental Protection
SCE's projected environmental capital expenditures are $2.0 billion for the 2002-2006 period, mainly for
undergrounding certain transmission and distribution lines. This amount has been increased from the amount
projected at December 31, 2001, to reflect the results from SCE's annual environmental cost study for 2001
completed in April 2002.
Electric and Magnetic Fields
Electric and magnetic fields (EMFs) naturally result from the generation, transmission, distribution and use of
electricity. Since the 1970s, concerns have been raised about the potential health effects of EMFs. After 30
years of research, a health hazard has not been established to exist. Many of the questions about specific
diseases have been successfully resolved due to an aggressive international research program. Potentially
important public health questions remain about whether there is a link between EMF exposures in homes or work and
some diseases, including childhood leukemia and a variety of other adult diseases (e.g., adult cancers and
miscarriages), and because of these questions, some health authorities have identified magnetic field exposures
as a possible human carcinogen.
In October 2002, the California Department of Health Services (CDHS) released its report evaluating the possible
risks from electric and magnetic fields (CDHS Report) to the CPUC and the public. The CDHS Report's conclusions
contrast with other recent reports by authoritative health agencies in that the CDHS has assigned a substantially
higher probability to the possibility that there is a causal connection between EMF exposures and a number of
diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis, and
miscarriages.
This report concludes a program initiated by the CPUC's 1993 Interim EMF Decision. Under the policies advanced
by that decision, utilities have already committed to funding research, providing education materials to
employees and customers, and taking proactive steps to lower magnetic fields from new facilities.
It is not yet clear what actions the CPUC will take to respond to the CDHS Report and to the recent EMF reports
by other health authorities such as the National Institute of Environmental Health Sciences, the World Health
Organization's International Agency for Research on Cancer, and the United Kingdom's National Radiation
Protection Board. Possible outcomes include, but are not limited to, continuation of current policies and
imposition of more stringent policies to implement greater reductions in EMF exposures. The different costs of
these outcomes is unknown at this time.
Navajo Nation Litigation
Peabody Holding Company (Peabody) supplies coal from mines on Navajo Nation lands to the Mohave Generating
Station. In June 1999, the Navajo Nation filed a complaint in federal 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.
Page 29
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.
Briefing on this matter has been completed and argument is scheduled for December 2002.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, nor the impact
on this complaint of the Navajo Nation's suit against the Government, or the impact of the complaint on the
operation of Mohave beyond 2005.
Employee Compensation and Benefit Plans
For detailed descriptions of Edison International's pension and stock options award plans, see Note 9 - Employee
Compensation and Benefit Plans, included in the notes to financial statements of SCE's 2001 annual report to
shareholders. As indicated in Note 9, SCE measures compensation expense related to stock-based compensation by
the intrinsic value method. If SCE were to adopt the fair-value method of accounting and charge the cost of the
stock options to expense, effective with stock options granted in 2002, earnings for the nine months ended
September 30, 2002, would have been reduced by approximately $644,000 and earnings for fiscal year 2002 would be
reduced by approximately $1.1 million, based on a Black-Scholes option-pricing model.
Under accounting standards for pension costs, if the accumulated benefit obligation exceeds the market value of
plan assets at the measurement date, the difference may result in a reduction to shareholder's equity. SCE's
next measurement date is December 31, 2002. As of September 30, 2002, the estimated accumulated benefit
obligation, measured using prevailing interest rates, compared to the estimated market value of the pension plan
assets, would not have resulted in a reduction to shareholder's equity.
San Onofre Inspection
SCE's San Onofre Unit 2 returned to service on July 2, 2002, after a 43-day outage for scheduled refueling and
maintenance. During this outage, a detailed inspection of the reactor vessel head nozzle penetrations was
conducted. The subject of reactor vessel head nozzle penetrations has received industry attention recently due
to the leakage from such nozzles at the Davis Besse nuclear plant in Ohio. The inspection conducted at San
Onofre Unit 2 found no indications of leakage or degradation in the reactor vessel head nozzle penetrations. San
Onofre Unit 3's nozzle penetrations will be inspected as part of its scheduled refueling and maintenance outage
in the first quarter of 2003.
Federal Income Taxes
On August 7, 2002, Edison International received a notice from the IRS asserting deficiencies in federal
corporate income taxes for Edison International's 1994 to 1996 tax years. The vast majority of the tax
deficiencies are timing differences and therefore, amounts ultimately paid, if any, would benefit Edison
International as future tax deductions. Edison International will challenge the deficiencies asserted by the
IRS. Edison International believes that it has meritorious legal defenses to those deficiencies and believes
that the ultimate outcome of this matter will not result in a material impact on Edison International's
consolidated results of operations or financial position.
NEW ACCOUNTING STANDARDS
On January 1, 2001, SCE adopted a new accounting standard for derivative financial instruments and hedging
activities. Adoption of this standard had no material impact on SCE's financial statements. Effective April 1,
2002, SCE also adopted an authoritative accounting interpretation to this standard, which precludes
Page 30
fuel contracts that have variable amounts from qualifying under the normal purchases and sales exception. The
adoption of this interpretation had no impact on SCE's financial statements.
SCE implemented the new Goodwill and Other Intangibles standard on January 1, 2002. Adoption of this standard
did not materially impact its results of operations or financial position.
A new accounting standard, Accounting for Asset Retirement Obligations, 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. The standard is
effective for SCE on January 1, 2003. SCE is studying the impact of the new standard and is unable to predict at
this time the impact on its financial statements.
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 appeals 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, fuel costs and other changes
in operating costs, which could affect the timing of SCE's past procurement cost recovery;
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 bodies setting rates, adopting or modifying cost recovery,
holding company rules, accounting and rate-setting mechanisms, as well as legislative or judicial
actions affecting the same matters (see Generation Procurement Proceeding discussions in the Regulatory
Matters section);
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 liabilities; and
o weather conditions, natural disasters, and other unforeseen events.
Page 31
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 November 7, 2002. 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 32
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, 2001 (2001 Form 10-K) and in Part II, Item 1 of SCE's Quarterly Report on Form 10-Q for the quarterly period
ending June 30, 2002 (Second Quarter 10-Q), 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.
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. 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. Following an 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 for that purpose. The Government filed for a
writ of certiorari to the United States Supreme Court which was granted on June 3, 2002. Briefing has been
completed and argument is scheduled for December 2002.
Qualifying Facilities Litigation
As previously reported in Part I, Item 3 of SCE's 2001 Form 10-K, and in Part II, Item 1 of SCE's Quarterly
Report on Form 10-Q for the quarterly period ending March 31, 2002 (First Quarter 10-Q) and Second Quarter 10-Q,
SCE has been involved in a number of legal actions brought by various QFs, alleging SCE's failure to timely pay
for power deliveries made from November 1, 2000, through March 26, 2001. The QF plaintiffs have included
gas-fired cogenerators and owners of solar, wind, geothermal and biomass projects, with the lawsuits, in
aggregate, seeking payments of more than $833,000,000 for energy and capacity supplied to SCE under QF contracts,
and in some cases additional damages. Many of these QF lawsuits also have sought an order allowing the suppliers
to stop providing power to SCE so that they may sell to other purchasers. Plaintiffs in most of these cases have
entered into settlement agreements providing for stays of litigation, payments to the QFs upon the occurrence of
specified conditions, modifications in some cases to the contract prices going forward, releases and dismissals
of the litigation upon payment by SCE. On March 1, 2002, and with several exceptions related to unique disputes
or other unique circumstances, including the status of regulatory approval, SCE paid the amounts due under the
settlement agreements with these QFs, which triggered the releases and other provisions effectuating the
settlements.
As a result of SCE's above-mentioned payments, and with certain exceptions described below, the lawsuits have
either been dismissed or are in the process of being dismissed.
o Cabazon Power Partners: Although previously stayed, the matter has been reactivated. Trial is now set
for April 2003.
o Salton Sea Power Generation, LP, IMC Chemicals, Inc. and Luz Solar Partners, Ltd. III: These lawsuits
have been dismissed.
Page 33
CPUC Litigation and Settlement
As previously reported in Part I, Item 3 of SCE's 2001 Form 10-K, in November 2000, SCE filed a complaint in
federal District Court against the Commissioners of the CPUC, alleging that their refusal to allow SCE to recover
its wholesale costs of purchasing power in its retail rates violated federal law. See the discussion under
Regulatory Matters, "CPUC Litigation Settlement Agreement" for a description of SCE's lawsuit against the CPUC,
its settlement (referred to as the CPUC Settlement Agreement), and the legal proceedings associated with the CPUC
Settlement Agreement, including the appeal thereof and the opinion and order on the appeal issued on
September 23, 2002, by the United States Court of Appeals for the Ninth Circuit.
South Coast Air Quality Management District Claims
In September 2002, SCE entered into a settlement with the South Coast Air Quality Management District in
satisfaction of claims that EPTC Dominguez Hills operated with a faulty gas flow meter which was attached to an
oil heater from 1999 through 2000. The alleged faulty gas flow meter caused the reporting of the gas usage to be
significantly less than the actual usage of gas in the heater. SCE paid a penalty of $127,750.00. The meter has
since been repaired.
CPUC Investigation Regarding SCE's Electric Line Maintenance Practices
On August 25, 2001, the CPUC issued an order instituting investigation (OII) regarding SCE's overhead and
underground electric line maintenance practices. The OII was based on a report issued by the CPUC's Protection
and Safety Consumer Services Division ("CPSD"), which alleges a pattern of noncompliance with the CPUC's General
Orders for the maintenance of electric lines over the period 1998 - 2000. The OII also alleges that noncomplying
conditions were "involved" in 37 accidents resulting in death, serious injury, or property damage. CPSD
identified 4,721 alleged violations of the General Orders during the three-year period; and the OII put SCE on
notice that it is potentially subject to a penalty of between $500 and $20,000 for each violation. The OII also
allowed the CPSD to allege additional violations of General Orders, as they are identified while the
investigation is pending.
In their opening brief on October 21, 2002, CPSD recommended a penalty of $97,080,000. SCE will respond to the
CPSD penalty recommendation in its reply brief by November 18, 2002. A decision is expected by year-end 2002 or
early 2003. See the discussion under Regulatory Matters, "Electric Line Maintenance Practices Proceeding" for
additional information.
Page 34
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, 2002 (File No. 1-2313, Form 10-K for year ended December 31, 2001)*
10.1 Amended and Restated Agreement for the Allocation of Income Tax Liabilities and Benefits among
Edison International, Southern California Edison Company and The Mission Group (File No.
1-9936, filed as Exhibit 10.3 to the Edison International Form 10-Q for the quarter ended
September 30, 2002)*
10.2 Administrative Agreement re Tax Allocation Payments among Edison International, Southern
California Edison Company, The Mission Group, Edison Capital, Mission Energy Holding Company,
Edison Mission Energy, Edison O&M Services, Edison Enterprises, and Mission Land Company (File
No. 1-9936, filed as Exhibit 10.3.4 to the Edison International Form 10-Q for the quarter ended
September 30, 2002)*
99 Statement Pursuant to 18 U.S.C. 1350
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
-------------- ---------- ----------------
September 23, 2002 September 24, 2002 5 and 7
- ------------------
* Incorporated by reference pursuant to Rule 12b-32.
Page 35
===================================================================================================================
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
November 14, 2002
===================================================================================================================
CERTIFICATION
I, ALAN J. FOHRER, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southern California Edison Company;
2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to
state a material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report,
fairly present in all material respects the financial condition, results of operations and cash flows of the registrant
as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior
to the filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were
significant changes in internal controls or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: Nov. 13, 2002
/s/ ALAN J. FOHRER
------------------------------------------
ALAN J. FOHRER
Chairman of the Board and Chief Executive Officer
===================================================================================================================
CERTIFICATION
I, W. JAMES SCILACCI., certify that:
1. I have reviewed this quarterly report on Form 10-Q of Southern California Edison Company;
2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to
state a material fact necessary to make the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly report;
3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report,
fairly present in all material respects the financial condition, results of operations and cash flows of the registrant
as of, and for, the periods presented in this quarterly report;
4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) designed such disclosure controls and procedures to ensure that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the
period in which this quarterly report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior
to the filing date of this quarterly report (the "Evaluation Date"); and
c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures
based on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the
registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent
function):
a) all significant deficiencies in the design or operation of internal controls which could adversely affect the
registrant's ability to record, process, summarize and report financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were
significant changes in internal controls or in other factors that could significantly affect internal controls subsequent
to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: Nov. 13, 2002
/s/ W. JAMES SCILACCI
--------------------------------
W. JAMES SCILACCI
Vice President and Chief Financial Officer