===================================================================================================================
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 June 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 August 9, 2002
----------------------------------------------------------- ---------------------------------------------------
Common Stock, no par value 434,888,104
===================================================================================================================
SOUTHERN CALIFORNIA EDISON COMPANY
INDEX
Page
No.
----
Part I. Financial Information:
Item 1. Consolidated Financial Statements:
Consolidated Statements of Income (Loss) - Three and Six Months
Ended June 30, 2002, and 2001 1
Consolidated Statements of Comprehensive Income (Loss) -
Three and Six Months Ended June 30, 2002, and 2001 1
Consolidated Balance Sheets - June 30, 2002,
and December 31, 2001 2
Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2002, and 2001 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Results
of Operations and Financial Condition 11
Item 3. Quantitative and Qualitative Disclosures About Market Risk 24
Part II. Other Information:
Item 1. Legal Proceedings 25
Item 4. Submission of Matters to a Vote of Security Holders 27
Item 6. Exhibits and Reports on Form 8-K 27
SOUTHERN CALIFORNIA EDISON COMPANY
PART I FINANCIAL INFORMATION
Item 1. Consolidated Financial Statements
CONSOLIDATED STATEMENTS OF INCOME (LOSS)
3 Months Ended 6 Months Ended
June 30, June 30,
-------------------------------------------------------------------------------------------------------------------
In millions 2002 2001 2002 2001
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Operating revenue $ 2,161 $ 1,592 $ 4,093 $ 3,104
-------------------------------------------------------------------------------------------------------------------
Fuel 50 51 102 98
Purchased power 581 807 835 2,531
Provisions for regulatory adjustment clauses - net (331) (90) 366 (119)
Other operation and maintenance 522 431 936 860
Depreciation, decommissioning and amortization 206 166 388 318
Property and other taxes 26 29 55 58
Net gain on sale of utility plant -- (6) -- (9)
-------------------------------------------------------------------------------------------------------------------
Total operating expenses 1,054 1,388 2,682 3,737
-------------------------------------------------------------------------------------------------------------------
Operating income (loss) 1,107 204 1,411 (633)
Interest and dividend income 54 25 163 51
Other nonoperating income 8 14 19 22
Interest expense - net of amounts capitalized (141) (153) (325) (360)
Other nonoperating deductions (5) (23) (9) (16)
-------------------------------------------------------------------------------------------------------------------
Net income (loss) before taxes 1,023 67 1,259 (936)
Income tax (benefit) 322 33 407 (377)
-------------------------------------------------------------------------------------------------------------------
Net income (loss) 701 34 852 (559)
Dividends on preferred stock 6 6 11 11
-------------------------------------------------------------------------------------------------------------------
Net income (loss) available for common stock $ 695 $ 28 $ 841 $ (570)
===================================================================================================================
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
3 Months Ended 6 Months Ended
June 30, June 30,
-------------------------------------------------------------------------------------------------------------------
In millions 2002 2001 2002 2001
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income (loss) $ 701 $ 34 $ 852 $ (559)
Other comprehensive income, net of tax:
Cumulative effect of change in accounting for derivatives -- -- -- 397
Unrealized gain (loss) on cash flow hedges 9 1 10 (422)
-------------------------------------------------------------------------------------------------------------------
Comprehensive income (loss) $ 710 $ 35 $ 862 $ (584)
===================================================================================================================
The accompanying notes are an integral part of these financial statements.
Page 1
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
June 30, December 31,
In millions 2002 2001
--------------------------------------------------------------------------------------------------------------------
(Unaudited)
ASSETS
Cash and equivalents $ 842 $ 3,414
Receivables, less allowances of $34 and $32
for uncollectible accounts at respective dates 802 1,093
Accrued unbilled revenue 553 451
Fuel inventory 10 14
Materials and supplies, at average cost 151 146
Accumulated deferred income taxes - net 35 433
Regulatory assets - net 58 83
Prepayments and other current assets 100 145
-------------------------------------------------------------------------------------------------------------------
Total current assets 2,551 5,779
-------------------------------------------------------------------------------------------------------------------
Nonutility property - less accumulated provision
for depreciation of $23 and $17 at respective dates 163 159
Nuclear decommissioning trusts 2,248 2,275
Other investments 210 224
-------------------------------------------------------------------------------------------------------------------
Total investments and other assets 2,621 2,658
-------------------------------------------------------------------------------------------------------------------
Utility plant, at original cost:
Transmission and distribution 13,766 13,568
Generation 1,747 1,729
Accumulated provision for depreciation and decommissioning (8,319) (7,969)
Construction work in progress 650 556
Nuclear fuel, at amortized cost 138 129
-------------------------------------------------------------------------------------------------------------------
Total utility plant 7,982 8,013
-------------------------------------------------------------------------------------------------------------------
Regulatory assets - net 5,728 5,528
Other deferred charges 481 475
-------------------------------------------------------------------------------------------------------------------
Total deferred charges 6,209 6,003
-------------------------------------------------------------------------------------------------------------------
Total assets $ 19,363 $ 22,453
===================================================================================================================
The accompanying notes are an integral part of these financial statements.
Page 2
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
June 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 1,172 1,146
Preferred stock to be redeemed within one year 9 105
Accounts payable 906 3,261
Accrued taxes 658 823
Other current liabilities 1,545 1,645
-------------------------------------------------------------------------------------------------------------------
Total current liabilities 4,290 9,107
-------------------------------------------------------------------------------------------------------------------
Long-term debt 5,635 4,739
-------------------------------------------------------------------------------------------------------------------
Accumulated deferred income taxes - net 3,209 3,365
Accumulated deferred investment tax credits 151 153
Customer advances and other deferred credits 840 739
Power-purchase contracts 319 356
Accumulated provision for pensions and benefits 490 420
Other long-term liabilities 154 148
-------------------------------------------------------------------------------------------------------------------
Total deferred credits and other liabilities 5,163 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 338 336
Accumulated other comprehensive income (loss) (12) (22)
Retained earnings 1,505 664
-------------------------------------------------------------------------------------------------------------------
Total common shareholder's equity 3,999 3,146
-------------------------------------------------------------------------------------------------------------------
Total liabilities and shareholder's equity $ 19,363 $ 22,453
===================================================================================================================
The accompanying notes are an integral part of these financial statements.
Page 3
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
6 Months Ended
June 30,
-------------------------------------------------------------------------------------------------------------------
In millions 2002 2001
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Cash flows from operating activities:
Net income (loss) $ 852 $ (559)
Adjustments to reconcile net income (loss) to
net cash provided (used) by operating activities:
Depreciation, decommissioning and amortization 388 318
Other amortization 50 36
Deferred income taxes and investment tax credits (132) (159)
Regulatory assets - long-term - net 220 (253)
Other assets 51 (85)
Other liabilities 127 76
Changes in working capital:
Receivables and accrued unbilled revenue 189 (132)
Regulatory liabilities - short-term - net 25 2
Fuel inventory, materials and supplies (2) (5)
Prepayments and other current assets 45 13
Accrued interest and taxes (200) (212)
Accounts payable and other current liabilities (2,391) 2,325
-------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by operating activities (778) 1,365
-------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issued 1,600 --
Long-term debt repaid (700) --
Bonds remarketed (repurchased) and funds held in trust 192 (130)
Redemption of preferred securities (100) --
Rate reduction notes repaid (115) (112)
Nuclear fuel financing - net (59) (10)
Short-term debt financing - net (2,127) 670
Dividends paid (32) (1)
-------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by financing activities (1,341) 417
-------------------------------------------------------------------------------------------------------------------
Cash flows from investing activities:
Additions to property and plant (463) (353)
Net funding of nuclear decommissioning trusts 7 20
Sales of investments in other assets 3 11
-------------------------------------------------------------------------------------------------------------------
Net cash used by investing activities (453) (322)
-------------------------------------------------------------------------------------------------------------------
Net increase (decrease) in cash and equivalents (2,572) 1,460
Cash and equivalents, beginning of period 3,414 583
-------------------------------------------------------------------------------------------------------------------
Cash and equivalents, end of period $ 842 $ 2,043
===================================================================================================================
The accompanying notes are an integral part of these financial statements.
Page 4
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments (which are of a normal recurring nature) necessary for a fair
presentation of the financial position, results of operations and cash flows in accordance with accounting
principles generally accepted in the United States for the periods covered by this report have been included.
The results of operations for the period ended June 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.
Certain reclassifications have been made to prior-period amounts to conform to the June 30, 2002, financial
statement presentation.
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 instruments and hedging activities.
Adoption of this standard had no material impact on SCE's financial statements. An authoritative accounting
interpretation issued in October 2001 precludes fuel contracts that have variable amounts from qualifying under
the normal purchases and sales exception effective April 1, 2002. 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 impact of the new standard and is unable to predict at
this time the impact on its financial statements.
Note 2. Regulatory Matters
California Public Utilities Commission Litigation Settlement Agreement
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 procurement-related obligations
account (PROACT) as of August 31, 2001. The Utility Reform Network (TURN), a consumer advocacy group, and other
parties are pursuing an appeal 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 the matter is now under submission. A decision could be issued at any time. SCE cannot predict
the outcome of the appeal or the impact that any outcome would have upon the stipulated judgment. Possible
outcomes could include affirmance, a return to the district court, a referral of a controlling state law question
to the California Supreme Court, or reversal of the stipulated judgment. SCE cannot predict whether or how a
ruling on the stipulated judgment could also affect the settlement agreement.
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
Page 5
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 for
writ of mandamus in the California Supreme Court against the CPUC. The FTCR's petition asserts that the CPUC
exceeded its authority and violated state law in approving the settlement agreement and stipulated judgment with
SCE, and that the CPUC further intends to exceed its authority and violate state law in proposing and consenting
to a bankruptcy reorganization plan for Pacific Gas and Electric Company (PG&E). The petition seeks 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 petition also seeks an injunction against the
CPUC's expenditure of taxpayer funds in proposing or consenting to a PG&E bankruptcy reorganization plan that
violates state law. The FTCR's petition expressly states that it does 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 does not request any judicial actions regarding the settlement agreement. The FTCR is not
a party to TURN's federal court appeal concerning the stipulated the judgment.
The CPUC filed its response to the petition on July 12, 2002, and the FTCR submitted its reply brief on July 19,
2002. The matter is currently pending before the California Supreme Court. SCE cannot predict the outcome of
this matter or whether the FTCR will attempt in this or other proceedings to prevent the CPUC from continuing to
perform its obligations under the settlement agreement.
Holding Company Proceeding
In April 2001, the CPUC issued an order instituting investigation that reopens the past CPUC decision authorizing
the 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 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. SCE and Edison International intend to challenge the
CPUC decision on the first priority condition (and Edison International intends to challenge the CPUC decision on
the jurisdictional matter) and are evaluating the timing and manner of doing so. SCE cannot predict what effects
this investigation or any subsequent actions by the CPUC may have on SCE.
Utility-Retained Generation Proceeding
On April 4, 2002, the CPUC issued a decision to return utility-retained generation (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
Page 6
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
after tax. 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. 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.
Wholesale Electricity Markets
On April 25, 2001, after months of extremely 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. The FERC did not set a specific expiration date for its
new market mitigation plan. SCE cannot predict 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.
After unsuccessful settlement negotiations among utilities, power sellers and state representatives, 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 2002 and further hearings are scheduled in August 2002.
SCE cannot predict the amount of any potential refunds. Under the settlement agreement with the CPUC, refunds
will be applied to reduce the PROACT balance.
Note 3. Purchased Power
SCE purchased power through the PX 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:
3 Months Ended 6 Months Ended
June 30, June 30,
--------------------------------------------------------------------------------------------------------------
In millions 2002 2001 2002 2001
--------------------------------------------------------------------------------------------------------------
(Unaudited)
PX/ISO:
Purchases $ 82 $ (446) $ 64 $ 635
Generation sales -- (382) -- 323
--------------------------------------------------------------------------------------------------------------
Purchased power - PX/ISO - net 82 (64) 64 312
Purchased power - bilateral contracts 15 37 30 89
Purchased power - interutility/QF contracts 484 834 741 2,130
--------------------------------------------------------------------------------------------------------------
Total $ 581 $ 807 $ 835 $ 2,531
==============================================================================================================
PX/ISO amounts for the six months ended June 30, 2002, and three months ended June 30, 2001, reflect billing
adjustments. These billing adjustments are recovered through the PROACT and have no impact on
Page 7
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
earnings. Since January 17, 2001, all other power 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. As
amended in December 2000 and March 2001, the lawsuit involved securities fraud claims arising from alleged
improper accounting for energy-cost undercollections. The second amended 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. On September 17,
2001, SCE and Edison International filed a motion to dismiss for failure to state a claim. On March 8, 2002, the
district court issued an order dismissing the complaint with prejudice. The plaintiffs have stipulated to
dismiss their appeal. On April 26, 2002, the federal court of appeals approved the parties' stipulation and
ordered the appeal dismissed 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 40 identified sites is $104 million. The ultimate
costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties
inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable
data for identified sites; the varying costs of alternative cleanup methods; developments resulting from
investigatory studies; the possibility of identifying additional sites; and the time periods over which site
remediation is expected to occur. SCE believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $288 million. The upper limit of this range of costs
was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes. 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 $49 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
Page 8
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
recorded a regulatory asset of $71 million for its estimated minimum environmental-cleanup costs expected to be
recovered through customer rates.
SCE's identified sites include several sites for which there is a lack of currently available information,
including the nature and magnitude of contamination, and the extent, if any, that SCE may be held responsible for
contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs
can be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the
next several years are expected to range from $10 million to $25 million. Recorded costs for the twelve months
ended June 30, 2002, were $19 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 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 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.
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 $40 million per year. Insurance premiums are charged to operating expense.
Page 9
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Spent Nuclear Fuel
Under federal law, the U.S. Department of Energy (DOE) is responsible for the selection and development of a
facility for disposal of spent nuclear fuel and high-level radioactive waste. Such a facility was to be in
operation by January 1998. However, the DOE did not meet its obligation. It is not certain when the DOE will
begin accepting spent nuclear fuel from San Onofre or from other nuclear power plants. Extended delays by the
DOE could lead to consideration of costly alternatives involving siting and environmental issues. SCE has paid
the DOE the required one-time fee applicable to nuclear generation at San Onofre through April 6, 1983
(approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to 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 10
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 six-month periods ended June 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 six-month periods ended June 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
SCE earned $695 million and $841 million for the three and six months ended June 30, 2002, compared to earnings
of $28 million and a loss of $570 million for the same periods in 2001. In 2002, earnings included 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 second quarter
earnings included $63 million (after tax) and the year-to-date loss included $724 million (after tax), in
procurement-related adjustments for undercollected power procurement costs. Excluding these adjustments in both
2002 and 2001, SCE's second quarter and year-to-date earnings in 2002 were $215 million and $361 million,
respectively, compared to earnings of $91 million and $154 million, respectively, for the same periods in 2001.
The quarterly increase of $124 million and year-to-date increase of $207 million primarily reflects increased
revenue from the implementation of the CPUC's April 2002 decision in SCE's performance-based ratemaking (PBR)
proceeding, the accrual of interest income on the procurement-related obligations account (PROACT) balance and
lower interest expense. SCE's increases in 2002 also reflect lower earnings in 2001 resulting from an extended
outage at the San Onofre Nuclear Generating Station. 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 six months of 2001, SCE had $724 million of power procurement
costs in excess of revenue, which were expensed as incurred.
Page 11
Based on the CPUC's January 23, 2002, resolution regarding the regulatory accounting for PROACT, 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 of December 31, 2001. 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
More than 95% 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 six months ended June 30, 2002, compared to the same periods in
2001. The increases were primarily 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 case would be allocated among SCE's customer classes. To compensate for a two-month
delay in collecting the 3(cent)surcharge, the CPUC authorized an additional 1/2(cent)surcharge for a 12-month period
beginning in June 2001, which contributed to the increase in revenue. In May 2002, the CPUC allowed the
continuation of the 1/2(cent)surcharge that was schedule 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 be reported as an increase to revenue and cash by as much as $200 million for
the remainder of 2002, but will have no impact on earnings (see Temporary Surcharge). The increase in revenue
from the surcharge was partially offset by a decrease in revenue arising from the credits given to direct access
customers in 2002, as compared to 2001, as a result of a significant increase in the number of direct access
customers in 2002. Amounts SCE bills to and collects from its customers for electric power purchased and sold by
the California Department of Water Resources (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 $255 million and $596 million
for the three- and six-month periods ended June 30, 2002, compared to $461 million and $718 million for the
three- and six-month periods ended June 30, 2001.
With respect to the decrease in revenue in 2002 arising from the credits given to direct access customers, 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 final 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 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 PROACT Regulatory
Asset section below.
Operating Expenses
Purchased-power expense decreased significantly for the three- and six-month periods ended June 30, 2002, as
compared to the respective periods in 2001. The decreases resulted primarily from lower expenses related to
qualifying facilities (QFs), bilateral contracts and interutility contracts. In addition, the six-month period
decrease reflects the absence of California Power Exchange (PX)/Independent System Operator (ISO) purchased-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 and second quarters of 2002, spot natural gas prices were significantly lower than the same
periods in 2001. The decrease in purchased-power expense related to bilateral contracts and interutility
contracts was also due to the decrease in natural gas prices.
Page 12
SCE has contracts with certain QFs in which Edison Mission Energy, a nonutility affiliate, has 49% - 50%
ownership interests. The terms and pricing of these contracts are approved by the CPUC. SCE's power purchases
from these facilities were $138 million and $221 million for the three and six months ended June 30, 2002,
compared to $185 million and $350 million for the respective periods in 2001. The decrease was attributable to
the effect of lower gas prices in the QF pricing formula adopted by the CPUC.
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. The increase for the three months
ended June 30, 2002, in PX/ISO purchased power was partially due to these invoicing adjustments.
Provisions for regulatory adjustment clauses decreased for the second quarter of 2002, compared to the same
period in 2001. The second quarter decrease in the provisions was primarily due to the impact of SCE's
implementation of CPUC decisions related to URG and the PBR mechanism, as well as the impact of other regulatory
issues, all partially offset by overcollections used to reduce the PROACT balance.
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). The decreases discussed above were
partially offset by 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.
These overcollections were used to reduce the PROACT balance.
Provisions for regulatory adjustment clauses increased for the six months ended June 30, 2002, compared to the
respective period in 2001, as a result of overcollections used to reduce the PROACT balance, partially offset by
the impact of the URG and PBR decisions discussed above.
Other operating and maintenance expense increased for the three- and six-month periods ended June 30, 2002,
compared to the same periods in 2001, primarily due to increases resulting from ISO-related grid management
expenses and expenses related to the San Onofre Unit 2 refueling outage that occurred during second quarter 2002.
Depreciation, decommissioning and amortization expense increased for both the three- and six- month periods ended
June 30, 2002, as compared to the respective periods in 2001, mainly due to an increase in depreciation expense
associated with distribution assets, as well as an increase related to 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 recover 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 13
Other Income and Deductions
Interest and dividend income increased for the three- and six-month periods ended June 30, 2002, compared to the
respective periods in 2001. The increase for the three-month period ended June 30, 2002, was 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 the second quarter of 2002. The increase for the year-to-date period is
primarily due to interest income earned on the PROACT balance.
Interest expense - net of amounts capitalized decreased for the three- and six-months ended June 30, 2002, mainly
due to lower short-term debt balances during 2002, partially offset by an increase in interest expense related to
higher long-term debt balances in second quarter 2002.
Other nonoperating deductions decreased for the three- and six-month periods ended June 30, 2002, primarily due
to lower accruals for regulatory matters in 2002.
Income Taxes
Income tax expense increased for both the three- and six-month periods in 2002, primarily due to the income tax
benefit SCE recorded in 2001 related to its power procurement cost undercollection and the deferred income tax
expense associated with the reestablishment of generation-related regulatory assets upon implementation of the
URG decision. The effective income tax rate for both periods decreased as a result of this benefit.
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 June 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.
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
Page 14
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 has notified the administrative agent that it will
prepay $300 million of this loan on August 14, 2002.
SCE expects to meet its continuing obligations in 2002 from remaining cash on hand and future operating cash
flows. Material factors affecting the timing of recovery of the PROACT balance are discussed below in PROACT
Regulatory Asset. SCE's liquidity after 2002, may, among other things, be affected by the matters described in
the CPUC Litigation Settlement Agreement and the Generation Procurement Proceeding sections.
Cash Flows from Operating Activities
Net cash used by operating activities for the six months ended June 30, 2002, was $778 million, compared to net
cash provided by operating activities of $1.4 billion for the six months ended June 30, 2001. In 2002, cash used
by operating activities was primarily due to SCE's March 2002 repayment of past-due obligations, mainly related
to purchased power, partially offset by overcollections used to reduce the PROACT balance during the first six
months of 2002. 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 provided by
operating activities also reflects the CPUC-approved surcharges (1(cent)per kWh in January 2001, 3(cent)per kWh in June
2001 and a temporary 1/2(cent)per kWh in June 2001) that were billed.
Cash Flows from Financing Activities
Net cash used by financing activities was $1.3 billion for the six months ended June 30, 2002, compared to net
cash provided by financing activities of $417 million for the six months ended June 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, and the long-term debt repayments in second quarter 2002. 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 has notified
the administrative agent that it will prepay $300 million of this loan on August 14, 2002.
In 2001, 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.
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
June 30, 2002, are: 2003 - $1.2 billion; 2004 - $1.5 billion; 2005 - $1.3 billion; 2006 - $447 million; and
Page 15
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 June 30, 2002, are $9 million
for each period 2003 through 2007. These amounts have been updated to reflect SCE's redemption of 100,000 shares
of Series 6.45% preferred stock due in second quarter 2002.
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 procurement costs (as defined in the
settlement agreement). SCE expects to recover its future procurement costs through ongoing ratemaking procedures.
Depending upon regulatory or legislative actions, SCE may resume procurement of its residual-net short (i.e., the
amount of energy SCE must procure for its customers from sources other than its own generating plants, power
purchase contracts and energy allocated by the CPUC from the CDWR contracts) beginning January 1, 2003. If SCE
is required to resume procurement responsibility, SCE's liquidity will be subject to market risk to the extent
there is not a regulatory or legislative framework in place to provide assurance of timely recovery of SCE's
costs of procuring power in retail rates. (See the discussion under Generation Procurement Proceeding below.)
Currently, SCE is seeking CPUC authority to enter into contracts for capacity and related natural gas and gas
transmission arrangements, for up to five years in length, to hedge its residual-net short exposure. To the
extent SCE is not allowed to enter into these contracts or the CPUC does not allow SCE to purchase sufficient
quantities to adequately hedge its risk, SCE could be subject to greater impacts from fluctuations in the market
price of energy. SCE's ability to enter into capacity contracts also will be affected by the current financial
condition of potential counterparties. Many potential counterparties with capacity products available were
recently downgraded below investment grade by the rating agencies. Even if the CPUC permits SCE to enter into
contracts, and if SCE is successful in finding counterparties, SCE would still be subject to commodity price
risk.
SCE's residual-net short exposure is significant during the first quarter of 2003, because of a planned refueling
outage of SONGS Unit 3. In the second half of 2003, this exposure declines significantly as more power
deliveries are scheduled to commence under existing CDWR contracts.
On July 17, 2002, the FERC issued an order implementing a market power mitigation program for the 11-state
western region. SCE cannot predict 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.
See additional discussion in CPUC Settlement Agreement, Generation Procurement Proceeding and Wholesale
Electricity Markets.
Page 16
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 are pursuing an appeal 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 the matter is now under
submission. A decision could be issued at any time. SCE cannot predict the outcome of the appeal or the impact
that any outcome would have upon the stipulated judgment. Possible outcomes could include affirmance, a return
to the district court, a referral of a controlling state law question to the California Supreme Court, or
reversal of the stipulated judgment. SCE cannot predict whether or how a ruling on the stipulated judgment could
also affect the settlement agreement.
In addition, under the settlement agreement with the CPUC, 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. Other provisions of the settlement agreement are described in the CPUC Litigation Settlement Agreement
(pages 10 and 11) disclosure in the year-end 2001 MD&A.
In April 2002, the Foundation for Taxpayer and Consumer Rights (FTCR), an advocacy group, filed a petition for
writ of mandamus in the California Supreme Court against the CPUC. The FTCR's petition asserts that the CPUC
exceeded its authority and violated state law in approving the settlement agreement and stipulated judgment with
SCE, and that the CPUC further intends to exceed its authority and violate state law in proposing and consenting
to a bankruptcy reorganization plan for Pacific Gas and Electric Company (PG&E). The petition seeks 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 petition also seeks an injunction against the
CPUC's expenditure of taxpayer funds in proposing or consenting to a PG&E bankruptcy reorganization plan that
violates state law. The FTCR's petition expressly states that it does 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 does 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.
The CPUC filed its response to the petition on July 12, 2002, and the FTCR submitted its reply brief on July 19,
2002. The matter is currently pending before the California Supreme Court. SCE cannot predict the outcome of
this matter or whether the FTCR will attempt in this or other proceedings to prevent the CPUC from continuing to
perform its obligations under the settlement agreement.
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 $1.6 billion at June 30, 2002. The June 30, 2002, balance includes a second
quarter 2002 decrease of $256 million to reflect the implementation of the URG decision described below.
Currently, SCE projects that it will
Page 17
recover the remaining balance of the procurement-related obligations in the PROACT by late 2003. Material
factors that would change SCE's estimate of the timing of PROACT recovery are:
o level of output of SCE's generating plants and contract power delivers (for example, higher than
forecasted output accelerates PROACT recovery);
o authorized revenue changes for distribution, transmission, and SCE retained-generation costs (see
discussion in URG Decision, Generation Procurement Proceeding, PBR Decision and CPUC GRC Proceeding);
o SCE's share of the CDWR revenue requirement (see discussion in CDWR Revenue Requirement Proceeding);
o disposition of 1/2(cent)temporary surcharge (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 regarding the historical procurement charge and
exit fees 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); 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 - 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. 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. 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 amount is to be collected from direct access customers by reducing
the existing generation credit given by 2.7(cent)per kWh. This credit reduction will be utilized to reduce the new
regulatory asset balance until the CPUC issues 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 new regulatory asset balance will 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. SCE had requested that direct access customers be responsible for $540
million of its past power procurement costs and will request the CPUC to modify its interim decision
accordingly. Once the interim decision becomes permanent, SCE expects to reduce the PROACT balance and create a
new regulatory asset. The net effect of this action will accelerate the timing of PROACT recovery.
Direct Access - Exit Fees. The CPUC allocated the CDWR's costs of power purchases among the California utilities
and each utility's customers. However, the CPUC deferred a decision on the responsibility of direct access
customers to pay a portion of the CDWR's costs. On June 6, 2002, parties submitted proposals to the CPUC
regarding the appropriate charges to these customers and methods for assessing those charges. Rebuttal testimony
has been filed and evidentiary hearings have been held.
Page 18
One of the issues in this case is the level of cap placed on total direct access surcharges (including the
Historical Procurement Charge). If the CPUC maintains that cap at the same 2.7(cent)per kWh, discussed above, total
annual revenue is expected to increase by about $320 million. About $120 million of this amount will be
contributed to the recovery of the new regulatory asset (credited to the PROACT) and the remaining approximately
$200 million will go toward paying direct access customers' responsibility for the CDWR's costs. Amounts
contributed by direct access customers to recover the CDWR's costs will result in a reduction of the CDWR's
revenue requirement to be paid by SCE's bundled service customers, increasing the amount of revenue applied to
the PROACT balance, thus expediting the recovery of the PROACT balance.
CDWR Revenue Requirement Proceeding
-----------------------------------
In accordance with an agreement SCE and the CDWR executed on February 28, 2002, SCE paid the CDWR for previously
delivered imbalance energy (plus interest) in three installments ($100 million on April 1, 2002; $150 million on
June 3, 2002; and the balance of $120 million on July 1, 2002). In a decision dated March 21, 2002, the CPUC
approved the February 28 agreement between SCE and the CDWR.
On June 14, 2002, the CDWR issued an updated revenue requirement of $5.5 billion for calendar year 2003, for its
bond costs and power procurement costs. Comments on the updated revenue requirement were submitted to the CDWR
on July 16, 2002. Based on some or all of those comments, the CDWR is expected to revise its updated revenue
requirement and file it with the CPUC in the third quarter of 2002. The CPUC will then determine how the updated
revenue requirement will be allocated among the customers of the California electric utilities. Based on the
2003 CDWR revenue requirement filing, SCE's share of the CDWR's revenue requirement for 2003 could increase by as
much as $400 million, assuming the same allocation percentage used by the CPUC in 2001 and 2002. On August 9,
2002, the CDWR issued a Notice of Significant Additional Material Relied Upon in Proposed Determination of a
Revenue Requirement. It appears from the information referenced in this notice that the CDWR could adopt a
revenue requirement as high as $5.8 billion for calendar year 2003, in which case SCE's share would likely be
higher then the $400 million discussed above. The CDWR revenue requirement is likely to be adjusted for
undercollections or overcollections in 2001-2002. At this time, SCE is unable to predict what effect, if any,
the 2003 CDWR revenue requirement will have on the timing of the PROACT recovery.
Temporary Surcharge
-------------------
As discussed in Operating Revenue, the CPUC allowed the continuation of the 1/2(cent)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 be reported as an increase to
revenue and cash by as much as $200 million for the remainder of 2002 and $350 million in 2003, but will have no
impact on earnings. SCE assumes this increased revenue will be used to offset the CDWR's higher revenue
requirement, and has incorporated that assumption in 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 through the end of 2002. Ratemaking for SCE's utility-retained
generation after 2002 will be determined through 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;
o Retains the incremental cost incentive pricing mechanism (ICIP) for San Onofre Units 2 and 3 through
2003;
Page 19
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 7.37% 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.
Generation Procurement Proceeding
---------------------------------
In October 2001, the CPUC directed 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. In its responses to the order, SCE stated, among other things, that any CPUC-approved
procurement framework must include 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. SCE also emphasized the necessity of regaining an investment-grade credit rating before
it resumes purchasing power for customers. Without an investment-grade credit rating, SCE would experience
difficulty in obtaining financing and entering into long-term power contracts to mitigate commodity price risks.
SCE also asked the CPUC to approve an interim procedure for SCE to enter into contracts jointly with the CDWR
primarily for early procurement of capacity. By joining with the CDWR (which counterparties are willing to enter
into long-term contracts with), SCE could obtain long-term contracts before the CDWR's power contracting
authority expires on December 31, 2002, and in advance of SCE regaining an investment-grade credit rating.
CPUC also is addressing the issue of allocating among the three major California utilities the energy that will
be provided under contracts already entered into by the CDWR. This allocation will affect SCE's residual net
short (i.e., the amount of energy SCE must procure for its customers from sources other than its own generating
plants and power purchase contracts, as well as, energy allocated to SCE's customers from the CDWR contracts).
The allocation may impact the timing of the PROACT balance recovery or require a rate increase to ensure SCE is
fully recovering its procurement costs.
On July 3, 2002, the California Legislature unanimously passed as an urgency measure Assembly Bill (AB) 57, which
states an intent for SCE and the other California utilities to resume procuring power for their customers by
January 1, 2003. The bill, which has not yet been delivered to the Governor for his signature, provides that a
procurement plan approved for a utility by the CPUC shall, 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. The
bill states 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.
The bill calls for the CPUC to make an allocation of electricity provided
Page 20
under the CDWR contracts among the utilities, and for the utilities to submit a procurement plan within 60 days
thereafter. After the CPUC approves a procurement plan, the bill requires the CPUC to allow at least 90 days
before the utilities resume procurement. The bill permits bilateral contracting and other hedging activities.
SCE believes that the bill, if signed into law, would provide a framework under which SCE's credit rating can be
restored and would set forth the criteria for a fully functional procurement and ratemaking plan.
If SCE were required to resume power procurement before it has an investment-grade credit rating, the cash
requirements could have an adverse effect on SCE's liquidity. SCE is unable to predict what effect the
generation procurement proceeding or AB 57, if signed by the Governor and enacted into law, will have on the
currently projected timing of PROACT recovery.
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. Since the passage of a legislative bill, which prevented completion of a pending
sale of SCE's share of Mohave, 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 negotiate to resolve the coal supply and slurry-water issues. If those issues are
satisfactorily resolved by the end of 2002, SCE's application states that 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 this 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 if the outstanding coal and
slurry-water issues are sufficiently resolved by year-end 2002; or b) authority for SCE to establish certain
balancing accounts and otherwise begin preparing to not extend Mohave's coal-fired operations at the end of 2005.
Several parties filed protests or responses to SCE's application on July 1, 2002. 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 outcome of SCE's application is not expected to impact Mohave's operation through 2005. Consequently, SCE
does not expect this matter to have a material impact on the PROACT balance or the timing its 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 under or overcollections resulting from changes in retail
Page 21
rates. A balancing account will be established to record any under or overcollections. This is
retroactively effective as of June 14, 2001.
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 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 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 expects its earnings for 2002 to increase by approximately $145 million.
During the second quarter of 2002, SCE recorded credits to earnings of approximately $26 million for revenue
undercollections during the period June 14, 2001, through December 31, 2001, and $23 million and $32 million for
revenue undercollections for the first and second quarters of 2002, respectively. SCE projects additional
credits to earnings for revenue undercollections of approximately $64 million during the remaining six months 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 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. Hearings are now scheduled to begin in the fourth quarter of 2002. A final
decision is expected in mid-2003.
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 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 2002 and further hearings are scheduled in August 2002. SCE cannot
predict 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. The FERC did not set a specific expiration date for its new market mitigation
plan. SCE cannot predict 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.
Page 22
Holding Company Proceeding
In April 2001, the CPUC issued an order instituting investigation that reopens the past CPUC decision authorizing
the 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. SCE and Edison
International intend to challenge the CPUC decision on the first priority condition (and Edison International
intends to challenge the CPUC on the jurisdictional matter) and are evaluating the timing and manner of doing
so. Edison International cannot predict what effects this investigation or any subsequent actions by the CPUC
may have on Edison International or any of its subsidiaries.
OTHER MATTERS
Environmental Remediation
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.
Long-Term Incentive Plans
For a detailed description of Edison International's long-term incentive plans, see the Stock Options and Other
Equity-Based Awards disclosure in Note 9-Employee Compensation and Benefit Plans 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 six months ended June
30, 2002, would have been reduced by approximately $150,000 and earnings for fiscal year 2002 would be reduced by
approximately $1 million, based on a Black-Scholes option-pricing model.
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 reactor vessel head nozzle penetrations have 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 Internal Revenue Service (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
Page 23
deficiencies asserted by the IRS. 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 consolidated results of operations or financial position.
NEW ACCOUNTING STANDARDS
SCE is studying the impact of the new Asset Retirement Obligations standard to be implemented in 2003, and is
unable to predict at this time the impact on its 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.
FORWARD-LOOKING INFORMATION AND RISK FACTORS
In the preceding MD&A and elsewhere in this quarterly report, the words estimates, expects, anticipates,
believes, 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 or ballot initiatives, 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 and natural gas or in operating costs, which
could affect the timing of SCE's 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;
o the effects of increased competition in energy-related businesses, including the market entrants and the
effects of new technologies that may be developed in the future;
o new or increased environmental liabilities; and
o weather conditions, natural disasters, and other unforeseen events.
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, on page 16 incorporated herein by reference to General Instruction D (1).
Page 24
PART II OTHER INFORMATION
Item 1. Legal Proceedings
San Onofre Personal Injury Litigation
As previously reported in Part 1, Item 3 of SCE's Annual Report on Form 10-K for the fiscal year ended December
31, 2001 (SCE 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), SCE was actively involved in four lawsuits claiming personal injuries
allegedly resulting from exposure to radiation at San Onofre. In addition, SCE was previously involved, along
with other defendants, in two earlier cases raising similar allegations. Plaintiffs in five of the cases had
reached an agreement with SCE to stay all proceedings in those matters, including trial, pending the results of
the November 17, 1995, case that was then before the Ninth Circuit Court of Appeals. The parties agreed that if
the plaintiffs in the November 17, 1995, lawsuit did not receive a favorable determination on their appeal, then
the five other lawsuits would be dismissed. If, however, the plaintiffs in the November 17, 1995, lawsuit
received a favorable determination on appeal, the other matters would proceed.
On May 20, 2002, the United States Supreme Court denied plaintiffs' petition for a writ of certiorari in the
November 17, 1995, lawsuit. Plaintiffs' time to seek rehearing of that denial expired on June 14, 2002. Because
the plaintiffs in the November 1995 lawsuit did not receive a favorable determination, the remaining five cases
have been dismissed with prejudice.
Navajo Nation Litigation
As previously reported in Part I, Item 3 of Edison International's 2001 Form 10-K, on June 18, 1999, SCE was
served with a complaint filed by the Navajo Nation in the United States District Court for the District of
Columbia (D.C. District Court) against Peabody Holding Company and certain of its affiliates (Peabody), Salt
River Project Agricultural Improvement and Power District, and SCE. The complaint asserts claims against the
defendants for, among other things, violations of the federal RICO statute, interference with fiduciary duties
and contractual relations, fraudulent misrepresentation by nondisclosure, and various contract-related claims.
On February 21, 2002, Peabody filed a demand to arbitrate in United States District Court in Arizona (Arizona
District Court) pursuant to a provision of their agreement with the Navajo Nation. At the same time, Peabody and
SCE filed cross claims against the Navajo Nation in the D.C. District Court action, alleging that the Navajo
Nation had breached a prior settlement agreement and award between Peabody and the Navajo Nation by filing their
lawsuit. Additionally, Peabody and SCE filed a motion to transfer the action to the Arizona District Court or to
stay the D.C. District Court action pending the outcome of arbitration-related proceedings. This motion was made
in conjunction with Peabody's seeking the order in the Arizona District Court for arbitration. The D.C. District
Court denied Peabody's and SCE's motion to transfer the action to Arizona, or to stay the action pending the
outcome of the proceeding in the Arizona District Court arbitration-related proceedings. Peabody and SCE have
appealed this ruling.
Peabody has filed a motion for summary judgment in the Arizona District Court proceeding, seeking an order that
some of the claims asserted by the Navajo Nation in the D.C. District Court action over royalty rates on coal
leases were resolved in a prior settlement and award between Peabody and the Navajo Nation. Alternatively,
Peabody seeks an order requiring the Navajo Nation to arbitrate the claims that are the subject of the D.C.
District Court action in Arizona. The Navajo Nation has moved to dismiss the Arizona District Court action or,
alternatively, to have the matter transferred and consolidated with the D.C. District Court action.
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 First Quarter
10-Q, SCE has been involved in a number of legal actions brought by various QFs, alleging SCE's
Page 25
failure to timely pay for power deliveries made from November 1, 2000, through March 26, 2001 (Payment Suspension
Period). 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 Inland Paperboard and Packaging, Inc. (Inland): SCE opposes Inland's claims. SCE has filed a motion
for summary judgment addressing several of Inland's claims. A hearing on this motion took place on August
6, 2002. The motion was not resolved at that time and a further hearing has been set for August 20, 2002.
Trial had been set for August 6, 2002, although the trial date has been vacated due to the filing of the
foregoing summary judgment motion.
o Cabazon Power Partners: Although previously stayed, the matter has been reactivated. Trial was
originally set to occur on October 2, 2002, but that trial date has been vacated and a new date is expected
to be set by the court.
o Watson Cogeneration Co., Midway-Sunset Cogeneration Company, U.S. Borax, Inc. (Borax), NP Cogen, Inc.
(NP Cogen), and Black Hills Ontario, LLC: The CPUC approved the application for approval of the settlement
agreement in the N.P. Cogen action and the lawsuit has been dismissed. In the Borax case, in exchange for
payment received, plaintiff has agreed to release its nonpayment-related claims against SCE after receiving
a March 1 payment from SCE. The Borax lawsuit has also been dismissed. SCE has sought Commission approval
of various aspects of the Watson, Midway-Sunset and Black Hills agreements. The Commission has not yet
ruled on SCE's application.
o Salton Sea Power Generation, LP, IMC Chemicals, Inc. and Luz Solar Partners, Ltd. III: These QFs have
been paid amounts owing under their settlement agreements with SCE. The remaining outstanding issues have
now been resolved and these parties have filed requests for dismissal of their lawsuits.
Page 26
Item 4. Submission of Matters to a Vote of Security Holders
At SCE's Annual Meeting of Shareholders on May 14, 2002, shareholders elected eleven nominees to the Board of
Directors. The number of broker non-votes for each nominee was zero. The number of votes cast for and withheld
from each Director-nominee were as follows:
Number of Votes
------------------------------------------------
Name For Withheld
----
------------------------- ----------------------
Alan J. Fohrer 463,470,466 390,328
Bradford M. Freeman 463,476,286 384,508
Joan C. Hanley 463,457,974 408,820
Bruce Karatz 463,427,520 433,274
Luis G. Nogales 463,425,826 434,968
Ronald L. Olson 463,468,180 392,614
James M. Rosser 463,454,146 406,648
Richard T. Schlosberg, III 463,421,176 439,618
Robert H. Smith 463,465,162 395,362
Thomas C. Sutton 463,476,598 384,196
Daniel M. Tellep 463,457,110 403,684
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 Director Nonqualified Stock Option Terms and Conditions under the Equity Compensation Plan
(File No. 1-9936, filed as Exhibit 10.1 to the Edison International Form 10-Q for the quarter
ended June 30, 2002)*
10.2 Director Deferred Compensation Plan as amended May 14, 2002 (File No. 1-9936, filed as Exhibit
10.4 to the Edison International Form 10-Q for the quarter ended June 30, 2002)*
10.3 Executive Grantor Trust Agreement Amendment 2002-1 (File No. 1-9936, filed as Exhibit 10.3 to
the Edison International Form 10-Q for the quarter ended June 30, 2002)*
10.4 Director Grantor Trust Agreement Amendment 2002-1 (File No. 1-9936, filed as Exhibit 10.4 to
the Edison International Form 10-Q for the quarter ended June 30, 2002)*
99 Statement Pursuant to 18 U.S.C. Section 1350
Page 27
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
-------------- ---------- ----------------
May 8, 2002 May 10, 2002 4 and 7
------------------
* Incorporated by reference pursuant to Rule 12b-32.
Page 28
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
August 14, 2002
