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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2003
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[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
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Commission File Number 1-2313
SOUTHERN CALIFORNIA EDISON COMPANY
(Exact name of registrant as specified in its charter)
California 95-1240335
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2244 Walnut Grove Avenue
(P. O. Box 800)
Rosemead, California 91770
(Address of principal executive offices) (Zip Code)
(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 (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes |X| No |_|
Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange
Act). Yes |_| No |X|
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest
practicable date:
Class Outstanding at August 12, 2003
- ---------------------------------------------------------- ---------------------------------------------------
Common Stock, no par value 434,888,104
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SOUTHERN CALIFORNIA EDISON COMPANY
INDEX
Page
No.
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Part I. Financial Information:
Item 1. Financial Statements:
Consolidated Statements of Income - Three and Six Months
Ended June 30, 2003 and 2002 1
Consolidated Statements of Comprehensive Income -
Three and Six Months Ended June 30, 2003 and 2002 1
Consolidated Balance Sheets - June 30, 2003
and December 31, 2002 2
Consolidated Statements of Cash Flows -
Six Months Ended June 30, 2003 and 2002 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 14
Item 3. Quantitative and Qualitative Disclosures About Market Risk 35
Item 4. Controls and Procedures 35
Part II. Other Information:
Item 1. Legal Proceedings 36
Item 4. Submission of Matters to a Vote of Security Holders 37
Item 6. Exhibits and Reports on Form 8-K 37
Signatures
SOUTHERN CALIFORNIA EDISON COMPANY
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2003 2002 2003 2002
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Operating revenue $ 2,394 $ 2,133 $ 4,217 $ 4,041
- -------------------------------------------------------------------------------------------------------------------
Fuel 49 50 107 102
Purchased power 722 581 1,174 835
Provisions for regulatory adjustment clauses - net 506 (359) 811 314
Other operation and maintenance 476 522 961 936
Depreciation, decommissioning and amortization 177 206 391 388
Property and other taxes 42 26 82 55
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Total operating expenses 1,972 1,026 3,526 2,630
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Operating income 422 1,107 691 1,411
Interest and dividend income 40 54 79 163
Other nonoperating income 21 8 49 19
Interest expense - net of amounts capitalized (114) (141) (239) (325)
Other nonoperating deductions (8) (5) (34) (9)
- -------------------------------------------------------------------------------------------------------------------
Net income before tax 361 1,023 546 1,259
Income tax 132 322 212 407
- -------------------------------------------------------------------------------------------------------------------
Net income 229 701 334 852
Dividends on preferred stock 4 6 7 11
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Net income available for common stock $ 225 $ 695 $ 327 $ 841
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2003 2002 2003 2002
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income $ 229 $ 701 $ 334 $ 852
Other comprehensive income, net of tax:
Amortization of cash flow hedges 1 9 1 10
- -------------------------------------------------------------------------------------------------------------------
Comprehensive income $ 230 $ 710 $ 335 $ 862
- -------------------------------------------------------------------------------------------------------------------
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 2003 2002
- --------------------------------------------------------------------------------------------------------------------
(Unaudited)
ASSETS
Cash and equivalents $ 994 $ 992
Restricted cash 46 47
Receivables, less allowances of $25 and $36
for uncollectible accounts at respective dates 766 767
Accrued unbilled revenue 594 437
Fuel inventory 15 12
Materials and supplies, at average cost 161 159
Accumulated deferred income taxes - net -- 42
Regulatory assets - net -- 509
Prepayments and other current assets 141 57
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Total current assets 2,717 3,022
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Nonutility property - less accumulated provision
for depreciation of $35 and $29 at respective dates 160 154
Nuclear decommissioning trusts 2,348 2,210
Other investments 271 214
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Total investments and other assets 2,779 2,578
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Utility plant, at original cost:
Transmission and distribution 14,539 14,202
Generation 1,461 1,457
Accumulated provision for depreciation and decommissioning (6,395) (8,094)
Construction work in progress 582 529
Nuclear fuel, at amortized cost 133 153
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Total utility plant 10,320 8,247
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Regulatory assets - net 3,358 3,838
Other deferred charges 547 629
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Total deferred charges 3,905 4,467
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Total assets $ 19,721 $ 18,314
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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 2003 2002
- --------------------------------------------------------------------------------------------------------------------
(Unaudited)
LIABILITIES AND SHAREHOLDER'S EQUITY
Short-term debt $ -- $ --
Long-term debt due within one year 281 1,671
Preferred stock to be redeemed within one year 9 9
Accounts payable 887 745
Accrued taxes 831 699
Accumulated deferred income taxes - net 21 --
Regulatory liabilities - net 69 --
Other current liabilities 1,460 1,439
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Total current liabilities 3,558 4,563
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Long-term debt 5,067 4,504
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Accumulated deferred income taxes - net 2,538 2,658
Accumulated deferred investment tax credits 145 148
Customer advances and other deferred credits 561 964
Power-purchase contracts 242 309
Accumulated provision for pensions and benefits 374 356
Asset retirement obligations 2,088 --
Other long-term liabilities 164 152
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Total deferred credits and other liabilities 6,112 4,587
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Commitments and contingencies
(Notes 2 and 3)
Preferred stock:
Not subject to mandatory redemption 129 129
Subject to mandatory redemption 141 147
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Total preferred stock 270 276
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Common stock (434,888,104 shares outstanding at each date) 2,168 2,168
Additional paid-in capital 343 340
Accumulated other comprehensive loss (15) (16)
Retained earnings 2,218 1,892
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Total common shareholder's equity 4,714 4,384
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Total liabilities and shareholder's equity $ 19,721 $ 18,314
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The accompanying notes are an integral part of these financial statements.
Page 3
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Six Months Ended
June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2003 2002
- -------------------------------------------------------------------------------------------------------------------
(Unaudited)
Cash flows from operating activities:
Net income $ 334 $ 852
Adjustments to reconcile net income to
net cash provided (used) by operating activities:
Depreciation, decommissioning and amortization 391 388
Other amortization 50 50
Deferred income taxes and investment tax credits (28) (132)
Regulatory assets - long-term - net 147 220
Power contracts collateral (10) --
Other assets 46 51
Other liabilities (152) 158
Changes in working capital:
Receivables and accrued unbilled revenue (155) 189
Regulatory assets - short-term - net 579 25
Fuel inventory, materials and supplies (5) (2)
Prepayments and other current assets (83) 45
Accrued interest and taxes 151 (200)
Accounts payable and other current liabilities 143 (2,391)
- -------------------------------------------------------------------------------------------------------------------
Net cash provided (used) by operating activities 1,408 (747)
- -------------------------------------------------------------------------------------------------------------------
Cash flows from financing activities:
Long-term debt issuance costs (11) (31)
Long-term debt repaid (729) (700)
Bonds remarketed and funds held in trust -- 192
Redemption of preferred stock (5) (100)
Rate reduction notes repaid (115) (115)
Nuclear fuel financing - net -- (59)
Short-term debt financing - net -- (527)
Dividends paid (8) (32)
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Net cash used by financing activities (868) (1,372)
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Cash flows from investing activities:
Additions to property and plant (540) (463)
Net funding of nuclear decommissioning trusts (1) 7
Sales of investments in other assets 3 3
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Net cash used by investing activities (538) (453)
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Net increase (decrease) in cash and equivalents 2 (2,572)
Cash and equivalents, beginning of period 992 3,414
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Cash and equivalents, end of period $ 994 $ 842
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The accompanying notes are an integral part of these financial statements.
Page 4
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary
for a fair presentation of the financial position, results of operations and cash flows in accordance with
accounting principles generally accepted in the United States for the periods covered by this report. The
results of operations for the period ended June 30, 2003 are not necessarily indicative of the operating results
for the full year.
The quarterly report should be read in conjunction with Southern California Edison's (SCE) 2002 Annual Report on
Form 10-K filed with the Securities and Exchange Commission.
Note 1. Summary of Significant Accounting Policies
Basis of Presentation
SCE's significant accounting policies were described in Note 1 of "Notes to Consolidated Financial Statements"
included in its 2002 Annual Report. SCE follows the same accounting policies for interim reporting purposes.
Certain prior-period amounts were reclassified to conform to the June 30, 2003 financial statement presentation.
New Accounting Principles
Effective January 1, 2003, SCE adopted a new accounting standard, Accounting for Asset Retirement Obligations,
which requires entities to record the fair value of a liability for a legal asset retirement obligation in the
period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by
increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its
present value each period, and the capitalized cost is depreciated over the useful life of the related asset.
Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a
gain or loss upon settlement. However, rate-regulated entities may recognize regulatory assets or liabilities as
a result of timing differences between the recognition of costs in accordance with this standard and the recovery
of costs through the rate-making process. Regulatory assets and liabilities may also be recorded if it is
probable that the asset retirement obligation (ARO) will be recovered through the rate-making process.
SCE's impact of adopting this standard was:
o SCE adjusted its nuclear decommissioning obligation to reflect the fair value of decommissioning its
nuclear power facilities. SCE also recognized AROs associated with the decommissioning of coal-fired
generation assets.
o At December 31, 2002, SCE had accrued $2.3 billion to decommission its nuclear facilities and
$12 million to decommission its share of a coal-fired generating plant, under accounting principles in effect
at that time. Of these amounts, $298 million to decommission its inactive nuclear facility was recorded in
other long-term liabilities, and the remaining $2.0 billion was recorded as a component of the accumulated
provision for depreciation and decommissioning on the consolidated balance sheets in the 2002 Annual Report.
Page 5
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
o As of January 1, 2003, SCE reversed the $2.3 billion it had previously recorded for decommissioning,
recorded the fair value of its AROs of approximately $2.0 billion in the deferred credits and other
liabilities section of the balance sheet, and increased its unamortized nuclear investment by $303 million.
The cumulative effect of a change in accounting principle from unrecognized accretion expense and
adjustments to depreciation, decommissioning and amortization expense recorded to date was a $354 million
after-tax gain, which under accounting standards for rate-regulated enterprises was deferred as a regulatory
liability, partially offset by a $235 million deferred tax asset, as of January 1, 2003. Accretion and
depreciation expense resulting from the application of the new standard is expected to be approximately $143
million in 2003. This cost will reduce the regulatory liability, with no impact on earnings. As of June
30, 2003, SCE's ARO for its nuclear facilities totaled approximately $2.1 billion and its nuclear
decommissioning trust assets had a fair value of $2.3 billion. If the new standard had been in place on
January 1, 2002, SCE's ARO as of that date would have been $1.98 billion. Approximately $1.97 billion
collected through rates for cost of removal of plant assets not considered to be legal obligations remain in
accumulated depreciation and decommissioning.
A new accounting standard, Accounting for Certain Financial Instruments with Characteristics of both Liabilities
and Equity, was issued in May 2003 and requires issuers to classify certain freestanding financial instruments as
liabilities. These freestanding liabilities include mandatorily redeemable financial instruments, obligations to
repurchase the issuer's equity shares by transferring assets and certain obligations to issue a variable number
of shares. The standard is effective for SCE on July 1, 2003. Upon implementation, SCE will reclassify its
preferred stock subject to mandatory redemption to the liability section of its consolidated balance sheets.
This item is currently classified between liabilities and equity. In addition, dividend payments on this
instrument will be recorded as interest expense on SCE's consolidated statements of income. SCE does not expect
implementation of the new standard to have a material impact on its financial statements.
Regulatory Assets and Liabilities
Regulatory assets, less regulatory liabilities, included in the consolidated balance sheets are:
June 30, December 31,
In millions 2003 2002
- ----------------------------------------------------------------------------------------------------------
PROACT - net $ 84 $ 574
Rate reduction notes - transition cost deferral 1,104 1,215
Unamortized nuclear investment - net 617 630
Unamortized coal plant investment - net 66 61
Other:
Flow-through taxes - net 1,303 1,336
Unamortized loss on reacquired debt 233 237
Environmental remediation 72 70
Asset retirement obligation (313) --
Regulatory balancing accounts and other - net 123 224
- ----------------------------------------------------------------------------------------------------------
Total $ 3,289 $ 4,347
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Page 6
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Stock-Based Employee Compensation
SCE has three stock-based employee compensation plans, which are described more fully in Note 7 of "Notes to
Consolidated Financial Statements" included in SCE's 2002 Annual Report. SCE accounts for these plans using the
intrinsic value method. Upon grant, no stock-based employee compensation cost is reflected in net income, as all
options granted under those plans had an exercise price equal to the market value of the underlying common stock
on the date of grant. The following table illustrates the effect on net income if SCE had used the fair-value
accounting method.
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------
In millions 2003 2002 2003 2002
- -------------------------------------------------------------------------------------------------------------------
Net income available for common stock, as reported $ 225 $ 695 $ 327 $ 841
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 1 1 2 2
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 1 1 3 1
- -------------------------------------------------------------------------------------------------------------------
Pro forma net income available for common stock $ 225 $ 695 $ 326 $ 842
- -------------------------------------------------------------------------------------------------------------------
Supplemental Cash Flows Information
Six Months Ended
June 30,
- ----------------------------------------------------------------------------------------------------------
In millions 2003 2002
- ----------------------------------------------------------------------------------------------------------
Non-cash investing and financing activities:
Details of senior secured credit facility transaction:
Retirement of credit facility $ -- $ (1,650)
Senior secured credit facility replacement -- 1,600
- ----------------------------------------------------------------------------------------------------------
Cash paid on retirement of credit facility $ -- $ (50)
- ----------------------------------------------------------------------------------------------------------
Details of long-term debt exchange offer:
Variable rate notes redeemed $ (966) $ --
First and refunding bonds issued 966 --
- ----------------------------------------------------------------------------------------------------------
Note 2. Regulatory Matters
Further information on regulatory matters, including proceedings for California Department of Water Resources
power purchases and revenue requirements, generation procurement, and utility-retained generation, is described
in Note 2 of "Notes to Consolidated Financial Statements" included in SCE's 2002 Annual Report.
California Public Utilities Commission (CPUC) Litigation Settlement Agreement
In 2001, SCE and the CPUC entered into a settlement of SCE's lawsuit against the CPUC, which sought a ruling that
SCE is entitled to full recovery of its past procurement-related costs. A key element of the settlement
agreement was the establishment of a $3.6 billion regulatory balancing account called the procurement-related
obligations account (PROACT) as of August 31, 2001. The Utility Reform Network
Page 7
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(TURN), a consumer advocacy group, and other parties appealed to the federal court of appeals seeking to overturn
the stipulated judgment of the district court that approved the settlement agreement. On March 4, 2002, the
court of appeals heard argument on the appeal, and on September 23, 2002 the court issued its opinion. In the
opinion, the court affirmed the district court on all claims, with the exception of the challenges founded upon
California state law, which the appeals court referred to the California Supreme Court. In sum, the appeals
court concluded that none of the substantive arguments based on federal statutory or constitutional law compelled
reversal of the district court's approval of the stipulated judgment.
However, the appeals court stated in its opinion that there is a serious question whether the settlement
agreement violated state law, both in substance and in the procedure by which the CPUC agreed to it. The appeals
court added that if the settlement agreement violated state law, the CPUC lacked capacity to consent to the
stipulated judgment, and the stipulated judgment would need to be vacated. The appeals court indicated that, on
a substantive level, the stipulated judgment appears to violate California's electric industry restructuring
statute providing for a rate freeze. The appeals court also indicated that, on a procedural level, the
stipulated judgment appears to violate California laws requiring open meetings and public hearings. Because
federal courts are bound by the pronouncements of the state's highest court on applicable state law, and because
the federal appeals court found no controlling precedents from California courts on the issues of state law in
this case, the appeals court issued a separate order certifying those issues in question form to the California
Supreme Court and requested that the California Supreme Court accept certification.
The California Supreme Court accepted the certification, reformulated one of the certified questions as SCE had
requested, and set a briefing schedule. After the completion of the filing of briefs by the respective parties,
including supplemental briefs at the request of the California Supreme Court about an issue related to
California's open meeting laws, the parties made oral arguments before the California Supreme Court at a hearing
on May 27, 2003. SCE expects the California Supreme Court to issue its decision on the certified questions by
August 25, 2003. Once the California Supreme Court rules, the matter will return to the federal court of appeals
for final disposition. In the meantime, the case is stayed in the federal appellate court. SCE continues to
operate under the settlement agreement, and also continues to believe it is probable that SCE's ultimate recovery
of its past procurement costs through regulatory mechanisms, including the PROACT, will be validated. However,
SCE cannot predict with certainty the outcome of the pending legal proceedings.
Electric Line Maintenance Practices Proceeding
In August 2001, the CPUC issued an Order Instituting Investigation (OII) regarding SCE's overhead and underground
electric line maintenance practices. The order was based on a report issued by the CPUC's Consumer Protection
and Safety Division (CPSD), which alleged a pattern of noncompliance with the CPUC's general orders for the
maintenance of electric lines over the period 1998-2000. The order also alleged that noncompliant conditions
were involved in 37 accidents resulting in death, serious injury or property damage. The CPSD identified 4,817
alleged violations of the general orders during the three-year period; and the order put SCE on notice that it
could be subject to a penalty of between $500 and $20,000 for each violation or accident. In its opening brief
on October 21, 2002, the CPSD recommended that SCE be assessed a penalty of $97 million.
On June 19, 2003, a CPUC administrative law judge issued a presiding officer's decision (POD) fining SCE $576,000
for alleged violations involving death, injury or property damage, failure to identify
Page 8
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
unsafe conditions or exceeding required inspection intervals. The POD imposes no fines for over 98% of the
alleged violations and does not find that any of the alleged violations compromised the integrity or safety of
SCE's electric system or were excessive compared to other utilities. The POD orders SCE to consult with the CPSD
and refine SCE's maintenance priority system consistent with the discussion in the POD. On July 21, 2003, SCE
filed an appeal opposing the POD's interpretation that all general order non-conformances are violations subject
to potential penalty. The CPSD also filed an appeal, challenging the fact that the POD did not, in fact,
penalize SCE for the 4,721 violations alleged by the CPSD in the OII. SCE, Pacific Gas & Electric (PG&E), San
Diego Gas & Electric (SDG&E) and the California Cable and Telecommunications Association filed responses
challenging the CPSD's appeal. The CPSD filed a response objecting to the intervention and appeals of PG&E,
SDG&E and the California Cable and Telecommunications Association.
Holding Company Proceeding
In April 2001, the CPUC issued an OII that reopens the past CPUC decisions authorizing utilities to form holding
companies and initiates an investigation into, among other things: whether the holding companies violated CPUC
requirements to give first priority to the capital needs of their respective utility subsidiaries; any additional
suspected violations of laws or CPUC rules and decisions; and whether additional rules, conditions, or other
changes to the holding company decisions are necessary. On January 9, 2002, the CPUC issued an interim decision
on the first priority condition. The decision stated that, at least under certain circumstances, the condition
includes the requirement that holding companies infuse all types of capital into their respective utility
subsidiaries when necessary to fulfill the utility's obligation to serve. The decision did not determine if any
of the utility holding companies had violated this condition, reserving such a determination for a later phase of
the proceedings. On February 11, 2002, SCE and Edison International filed an application before the CPUC for
rehearing of the decision. On July 17, 2002, the CPUC affirmed its earlier decision on the first priority
condition and also denied Edison International's request for a rehearing of the CPUC's determination that it had
jurisdiction over Edison International in this proceeding. On August 21, 2002, Edison International and SCE
jointly filed a petition requesting a review of the CPUC's decisions with regard to first priority
considerations, and Edison International filed a petition for a review of the CPUC decision asserting
jurisdiction over holding companies, both in state court as required. PG&E and SDG&E and their respective
holding companies filed similar challenges, and all cases have been transferred to the First District Court of
Appeals in San Francisco. The CPUC filed briefs in opposition to the writ petitions. Edison International, SCE
and the other petitioners filed reply briefs on March 6, 2003. No hearings have been scheduled. The court may
rule without holding hearings. SCE cannot predict with certainty what effects this investigation or any
subsequent actions by the CPUC may have on it.
Mohave Generating Station Proceeding
As discussed in Note 2 of "Notes to Consolidated Financial Statements" included in SCE's 2002 Annual Report, on
May 17, 2002, SCE filed with the CPUC an application to address certain issues (mainly coal and slurry-water
supply issues) facing the future extended operation of Mohave. The uncertainty over a post-2005 coal and water
supply has prevented SCE and other Mohave co-owners from starting to make approximately $1.1 billion (SCE's share
is $605 million) of Mohave-related investments if Mohave's operations are to be extended past 2005. The CPUC
issued a ruling on January 7, 2003 requesting further written testimony on specified issues related to Mohave and
its coal and slurry-water supply issues to determine whether it is in the public interest to extend Mohave
operations post 2005. SCE submitted supplemental testimony on January 30, 2003 stating, among other things, that
the currently available information is not sufficient for the CPUC to make such a determination at this time.
Page 9
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Several further rounds of testimony and other filings have been submitted in 2003 by SCE and the other parties in
the proceeding, most recently on July 1, 2003. The Navajo Nation and Hopi Tribe and the coal mining company,
Peabody Western Coal Company, currently take the position that the CPUC should, among other things, require SCE
to fund a study of a possible alternative water supply, and require SCE to commence a CPUC proceeding for
authorization of the Mohave pollution controls and other plant investments. Certain other parties have taken the
position that SCE should be authorized to prepare for a year-end 2005 shutdown of Mohave. To date there has been
no substantive decision by the CPUC, and it is possible that further written filings or hearings will be
required. Negotiations also have continued among the relevant parties in an effort to resolve the coal and water
supply issues, so far without any resolution.
Wholesale Electricity and Gas Markets
In response to a consolidated proceeding related to the justness and reasonableness of rates charged by sellers
in the California Power Exchange and Independent System Operator markets as described in Note 2 of "Notes to
Consolidated Financial Statements" included in SCE's 2002 Annual Report, the FERC issued orders that initiated
procedures for determining additional refunds arising from market manipulation by energy suppliers. A FERC staff
report issued on March 26, 2003 found that there was pervasive gaming and market manipulation of the electric and
gas markets in California and in the west coast and also described many of the techniques and effects of electric
and gas market manipulation. In a March 26, 2003 order, clarified on April 22, 2003, the FERC adopted a
recommendation of the FERC staff's final report to modify the ALJ's initial decision of December 12, 2002 to
reflect the fact that the gas indices used in the market manipulation formula overstated the cost of gas used to
generate electricity. SCE, as a member of the California parties, sought rehearing of the March 26 and April 22
orders. On June 25, 2003, the FERC issued two sets of enforcement orders. The first set orders 54 entities,
including SCE, to show cause concerning gaming or anomalous market behavior during the period January 1, 2001 to
June 20, 2001. The second set orders 25 entities to show cause concerning gaming and anomalous market behavior
in concert with Enron entities. Under both sets of orders, the remedy for tariff violations will be the
disgorgement of unjust profits and possibly other non-monetary remedies. On June 25, 2003, the FERC also opened
a new investigation into anomalous bidding behavior during the period May 1, 2000 to October 2, 2000, focused
primarily on economic withholding by bidding above $250/MWh with disgorgement of profits as the possible
penalty. SCE cannot, at this time, determine the timing or amount of any potential refunds. Under the
settlement agreement with the CPUC, 90% of any refunds will be given to ratepayers and 10% would be given to
shareholders. The CPUC issued an order instituting rulemaking on July 10, 2003, to account for the consideration
received by regulated gas and electric utilities under a settlement with El Paso Natural Gas Company, et al.
Under the terms of the rulemaking, SCE will refund amounts (net of legal and consulting costs) through its ERRA
balancing account as they are received from El Paso under the terms of the settlement. In addition, amounts El
Paso refunds to the CDWR will result in equivalent reductions in the CDWR's revenue requirement from SCE's
ratepayers.
Note 3. Contingencies
In addition to the matters disclosed in these Notes, SCE is involved in other legal, tax and regulatory
proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of
business. SCE believes the outcome of these other proceedings will not materially affect its results of
operations or liquidity.
Page 10
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 39 identified sites is $101 million. The sites
include SCE's divested gas-fueled generation plants, for which SCE retained some liability after their sale. The
ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous
uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity
of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting
from investigatory studies; the possibility of identifying additional sites; and the time periods over which site
remediation is expected to occur. SCE believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $277 million. The upper limit of this range of costs
was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes.
The CPUC allows SCE to recover environmental remediation costs at certain sites, representing $40 million of its
recorded liability, through an incentive mechanism (SCE may request to include additional sites). Under this
mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%,
with the opportunity to recover these costs from insurance carriers and other third parties. SCE has
successfully settled insurance claims with all responsible carriers. SCE expects to recover costs incurred at
its remaining sites through customer rates. SCE has recorded a regulatory asset of $72 million for its estimated
minimum environmental-cleanup costs expected to be recovered through customer rates.
SCE's identified sites include several sites for which there is a lack of currently available information,
including the nature and magnitude of contamination and the extent, if any, that SCE may be held responsible for
contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs
can be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the
next several years are expected to range from $15 million to $25 million. Recorded costs for the twelve months
ended June 30, 2003 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
Page 11
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
materially affect its results of operations or financial position. There can be no assurance, however, that
future developments, including additional information about existing sites or the identification of new sites,
will not require material revisions to such estimates.
Federal Income Taxes
In August 2002, Edison International received a notice from the Internal Revenue Service asserting deficiencies
in federal corporate income taxes for its 1994 to 1996 tax years. Included in these amounts are deficiencies
asserted against SCE. The vast majority of SCE's tax deficiencies are timing differences and, therefore, amounts
ultimately paid, if any, would benefit it as future tax deductions. SCE believes that it has meritorious legal
defenses to deficiencies asserted against it and believes that the ultimate outcome of this matter will not
result in a material impact on its results of operations or financial position.
Navajo Nation Litigation
Peabody Holding Company (Peabody) supplies coal from mines on Navajo Nation lands to Mohave. In June 1999, the
Navajo Nation filed a complaint in the United States District Court for the District of Columbia (D.C. District
Court) against Peabody and certain of its affiliates, Salt River Project Agricultural Improvement and Power
District, and SCE. The complaint asserts claims against the defendants for, among other things, violations of
the federal RICO statute, interference with fiduciary duties and contractual relations, fraudulent
misrepresentation by nondisclosure, and various contract-related claims. The complaint claims that the
defendants' actions prevented the Navajo Nation from obtaining the full value in royalty rates for the coal. The
complaint seeks damages of not less than $600 million, trebling of that amount, and punitive damages of not less
than $1 billion, as well as a declaration that Peabody's lease and contract rights to mine coal on Navajo Nation
lands should be terminated.
In February 2002, Peabody and SCE filed cross claims against the Navajo Nation, alleging that the Navajo Nation
had breached a settlement agreement and final award between Peabody and the Navajo Nation by filing their lawsuit.
The Navajo Nation had previously filed suit in the Court of Claims against the United States Department of
Interior, alleging that the Government had breached its fiduciary duty concerning contract negotiations including
the Navajo Nation and the defendants. In February 2000, the Court of Claims issued a decision in the
Government's favor, finding that while there had been a breach, there was no available redress from the
Government. Following appeal of that decision by the Navajo Nation, an appellate court ruled that the Court of
Claims did have jurisdiction to award damages and remanded the case to the Court of Claims for that purpose. On
June 3, 2002, the Government's request for review of the case by the United States Supreme Court was granted. On
March 4, 2003, the Supreme Court reversed the appellate court and held that the Government is not liable to the
Navajo Nation as there was no breach of a fiduciary duty and that the Navajo Nation did not have a right to
relief against the Government. Based on the Supreme Court's analysis, on April 28, 2003, SCE filed a motion to
dismiss or, in the alternative, for summary judgment in the D.C. District Court action. The motion remains
pending.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, nor the impact
on this complaint or the Supreme Court's decision on the outcome of the Navajo Nation's suit against the
government, or the impact of the complaint on the operation of Mohave beyond 2005.
Page 12
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $9.5 billion ($10.9 billion as of
August 20, 2003). SCE and other owners of the San Onofre and Palo Verde Nuclear Generating Stations have
purchased the maximum private primary insurance available ($300 million). The balance is covered by the
industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear
incident at any licensed reactor in the U.S. results in claims and/or costs which exceed the primary insurance at
that plant site. Federal regulations require this secondary level of financial protection. The Nuclear
Regulatory Commission exempted San Onofre Unit 1 from this secondary level, effective June 1994. The maximum
deferred premium for each nuclear incident is $88 million ($101 million as of August 20, 2003) 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 ($199 million as of August 20, 2003) per
nuclear incident. However, it would have to pay no more than $20 million per incident in any one year. Such
amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject
to adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose
further revenue-raising measures to pay claims, including a possible additional assessment on all licensed
reactor operators. The U.S. Congress has extended the expiration date of the applicable law until December 31,
2003 and is considering amendments that, among other things, are expected to extend the law beyond 2003.
Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and
Palo Verde. Decontamination liability and property damage coverage exceeding the primary $500 million also has
been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement
power expenses during an accident-related nuclear unit outage. A mutual insurance company owned by utilities
with nuclear facilities issues these policies. If losses at any nuclear facility covered by the arrangement were
to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium
adjustments of up to $38 million per year. Insurance premiums are charged to operating expense.
Spent Nuclear Fuel
Under federal law, the U.S. Department of Energy (DOE) is responsible for the selection and development of a
facility for disposal of spent nuclear fuel and high-level radioactive waste. Such a facility was to be in
operation by January 1998. However, the DOE did not meet its obligation. It is not certain when the DOE will
begin accepting spent nuclear fuel from San Onofre or from other nuclear power plants. Extended delays by the
DOE could lead to consideration of costly alternatives involving siting and environmental issues. SCE has paid
the DOE the required one-time fee applicable to nuclear generation at San Onofre through April 6, 1983
(approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to 0.1(cent)per kWh
of nuclear-generated electricity sold after April 6, 1983.
SCE, as operating agent, has primary responsibility for the interim storage of spent nuclear fuel generated at
San Onofre. The spent nuclear fuel is stored in the San Onofre Units 1, 2 and 3 spent fuel pools. The Units 2
and 3 spent fuel pools currently contain 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
begin moving the Unit 1 spent fuel to a dry cask interim spent fuel storage facility at San Onofre by the third
quarter of 2003. By late 2004, the spent fuel pool storage capacity for Units 2
Page 13
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.
In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed a
dry cask storage facility. Arizona Public Service Company (APS), operating agent for Palo Verde, has loaded five
casks for Unit 2 and one for Unit 1. APS plans to continually load casks on a schedule to maintain full core
off-load capability for all three units.
Note 4. Subsequent Event
On July 17, 2003, SCE signed an option agreement with Sequoia Generating LLC (Sequoia), a subsidiary of InterGen,
to acquire Mountainview Power Company LLC, the owner of a new power plant currently being developed in Redlands,
California. This acquisition requires regulatory approval from both the CPUC and the Federal Energy Regulatory
Commission (FERC). SCE has filed an application with the CPUC proposing a power-purchase agreement between SCE
and Mountainview Power Company LLC. If approved by the CPUC, SCE will seek FERC approval of the power-purchase
agreement. SCE does not expect to exercise the option without CPUC and FERC approvals. The option must be
exercised prior to February 29, 2004. If SCE exercises the option, SCE would recommence full construction of the
project. Under the option agreement, Sequoia may elect to terminate the option agreement at any time prior to
SCE's exercise of the option. In such event, Sequoia must return all previously tendered option payments.
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
This Management's Discussion and Analysis of Financial Condition and Results of Operations (MD&A) for the three-
and six-month periods ended June 30, 2003, discusses material changes in the results of operations, financial
condition and other developments of Southern California Edison Company (SCE) since December 31, 2002, and as
compared to the three- and six-month periods ended June 30, 2002. This discussion presumes that the reader has
read or has access to SCE's MD&A for the calendar year 2002 (the year-ended 2002 MD&A), which was included in
SCE's 2002 annual report to shareholders and incorporated by reference into SCE's Annual Report on Form 10-K for
the year ended December 31, 2002.
This MD&A contains forward-looking statements. These statements are based on SCE's knowledge of present facts,
current expectations about future events and assumptions about future developments. Forward-looking statements
are not guarantees of performance; they are subject to risks, uncertainties and assumptions that could cause
actual future activities and results of operations to be materially different from those set forth in this MD&A.
Important factors that could cause actual results to differ include, but are not limited to, risks discussed
below under "Financial Condition," "Market Risk Exposures" and "Forward-Looking Information and Risk Factors."
The following discussion provides updated information about material developments since the issuance of the
year-ended 2002 MD&A and should be read in conjunction with the financial statements contained in this quarterly
report and SCE's Annual Report on Form 10-K for the year ended December 31, 2002.
This MD&A includes information about SCE, a regulated public utility company providing electricity to retail
customers in central, coastal, and southern California.
CURRENT DEVELOPMENTS
As discussed in detail in "Regulatory Matters--CPUC Litigation Settlement Agreement," SCE entered into a
settlement agreement with the California Public Utilities Commission (CPUC) that allowed SCE to recover $3.6
billion in past procurement-related costs. The Utility Reform Network (TURN), a consumer advocacy group, and
other parties appealed to the federal court of appeals seeking to overturn the district court judgment that
approved the settlement agreement. In September 2002, an appeals court opinion affirmed the district court on
all claims, with the exception of challenges founded upon California state law, which the appeals court referred
to the California Supreme Court. On May 27, 2003, the parties made oral arguments before the California Supreme
Court. SCE expects the California Supreme Court to issue its decision on the certified questions of state law by
August 25, 2003.
As discussed in "Regulatory Matters--PROACT Regulatory Asset and--Customer Rate-Reduction Plan," SCE fully
recovered the procurement-related obligations account (PROACT) balance during July 2003. As a result of
recovering the PROACT balance, SCE implemented a CPUC-approved customer rate-reduction plan effective August 1,
2003. The customer rate-reduction plan reduces SCE's annual rates by $1.2 billion (with no impact to earnings)
and will reduce bills by 8% for residential customers, 18% for small businesses, 13% for medium businesses and
19% for large businesses.
RESULTS OF OPERATIONS
Earnings
SCE's earnings for the three- and six-month periods ended June 30, 2003 were $225 million and $327 million,
respectively, compared with $695 million and $841 million for the same periods in 2002. Excluding the $480
million adjustment related to the utility retained generation (URG) decision in 2002, SCE's second quarter and
year-to-date 2002 earnings were $215 million and $361 million, respectively.
Page 14
Excluding the URG adjustment, earnings for second quarter 2003 increased $10 million over second quarter 2002,
primarily due to the impact of two items that occurred in second quarter 2002 that did not occur in second
quarter 2003: a refueling outage at San Onofre Nuclear Generating Station (San Onofre) Unit 2 and a one-time
positive adjustment related to the implementation of a sales adjustment mechanism. Excluding the $480 million
gain to implement the URG decision, SCE's earnings in the first half of 2003 decreased by $34 million, compared
to the same period in 2002. The decrease primarily reflects the impact of a one-time positive adjustment
relating to the implementation of a sales adjustment mechanism that occurred in the second quarter of 2002.
Additionally, SCE had higher operating and maintenance expenses, including health care and storm damage costs,
which were offset by higher revenue.
Operating Revenue
SCE's retail sales represented approximately 91% of operating revenue for both the second quarter and
year-to-date ended June 30, 2003, and 96% of operating revenue for the same periods in 2002. Retail rates are
regulated by the CPUC and wholesale rates are regulated by the Federal Energy Regulatory Commission (FERC).
Due to warmer weather and higher electricity usage during the summer months, operating revenue during the third
quarter of each year is significantly higher than other quarters.
Operating revenue increased for the three- and six-month periods ended June 30, 2003, compared to the same
periods in 2002, primarily due to increased revenue from wholesale and retail customers. Wholesale revenue
increased due to the resale of SCE's excess energy, compared to no excess energy sales in 2002. As a result of
the California Department of Water Resources (CDWR) contracts allocated to SCE, excess energy from SCE sources
may exist at certain times and is resold in the energy markets. Retail sales revenue increased mainly due to
recognition of revenue from amortization of the temporary surcharge that was collected in 2002 and authorized by
the CPUC to be used to recover costs incurred in 2003 (see "Regulatory Matters--Surcharge Decisions" in the
year-ended 2002 MD&A for further discussion) and higher revenue resulting from a net 1(cent)per kilowatt hour (kWh)
decrease in credits given to direct access customers. During the period January 1, 2002 through July 27, 2002,
direct access customers were given an average credit of 11(cent)per kWh. This average credit was reduced to 8.3(cent)per
kWh on July 27, 2002, to collect a nonbypassable historical procurement charge, causing SCE's revenue to increase
by 2.7(cent)per kWh through the end of 2002. Beginning on January 1, 2003, SCE's share of the nonbypassable
historical procurement charge was reduced to 1(cent)per kWh, with the remaining 1.7(cent)per kWh allocated and remitted
to CDWR for its costs associated with direct access customers (see discussion below). The increases were
partially offset by an increase in amounts remitted to CDWR for energy purchases, including an allocation
adjustment during the six-month period ended June 30, 2003, bond-related charges (beginning November 15, 2002)
and direct access exit fees (beginning January 1, 2003).
From 1998 through mid-September 2001, SCE's customers were able to choose to purchase power directly from an
energy service provider other than SCE (thus becoming direct access customers) or continue to have SCE purchase
power on their behalf. On March 21, 2002, the CPUC issued a decision affirming that new direct access
arrangements entered into by SCE's customers after September 20, 2001 were invalid. Direct access arrangements
entered into prior to September 20, 2001 remain valid. Direct access customers continue to be given an average
credit of 8.3(cent)per kWh, for the generation costs SCE saves by not serving them. Operating revenue is reported
net of this credit. See "Regulatory Matters--Direct Access Proceedings" discussion.
Amounts SCE bills and collects from its customers for electric power purchased and sold by CDWR to SCE's
customers (beginning January 17, 2001), CDWR bond-related costs (beginning November 15,
Page 15
2002) and direct access exit fees (beginning January 1, 2003) are remitted to CDWR and are not recognized as
revenue by SCE. These amounts were $421 million and $845 million for the three- and six-month periods ended June
30, 2003, respectively, compared to $255 million and $596 million for the three- and six-month periods ended June
30, 2002, respectively.
Operating Expenses
Purchased-power expense increased for both the quarter and year-to-date ended June 30, 2003, compared to the same
periods in 2002, mainly due to higher expenses related to power purchased by SCE from qualifying facilities
(QFs), as discussed below, as well as higher expenses related to SCE's bilateral contracts and interutility
contracts.
Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated
prices. Energy payments to gas-fired QFs are generally tied to spot natural gas prices. Effective May 2002,
energy payments for most renewable QFs were converted to a fixed price of 5.37(cent)per kWh, compared with an average
of 3.1(cent)per kWh during the period between January and April 2002. During 2003, spot natural gas prices were
higher compared to the same period in 2002. The 2003 increase in purchased-power expense related to SCE's
bilateral and interutility contracts was also due to the increase in spot natural gas prices, as well as an
increase in the number of bilateral contracts entered into during 2003.
Provisions for regulatory adjustment clauses - net increased for both the three- and six-month periods ended
June 30, 2003, compared to the same periods in 2002. The three- and six-month period increases were mainly due to
SCE's reestablishment of regulatory assets related to its unamortized nuclear facilities, purchased-power
settlements and flow-through taxes recorded in 2002, partially offset by a decrease in overcollections used to
recover the PROACT balance resulting primarily from higher QF costs. The six-month period ended June 30, 2003
increase was also partially offset by an allocation adjustment for CDWR energy purchases.
Other operating and maintenance expense decreased for the three-month period ended June 30, 2003 mainly due to
higher Independent System Operator (ISO) administrative costs during 2002. Other operating and maintenance
expense increased during the six-month period ended June 30, 2003, as compared to the same period in 2002, mainly
due higher health-care costs, higher storm damage expenses, and higher spending on certain CPUC-authorized
programs, partially offset by lower ISO administrative costs.
Depreciation, decommissioning and amortization expense decreased during the second quarter of 2003, compared to
the same period in 2002, mainly due to a decrease in SCE's nuclear decommissioning expense, a decrease in
amortization due to the change in the amortization period of SCE's nuclear facilities based on the URG decision
received in the second quarter of 2002, partially offset by an increase in depreciation expense associated with
SCE's additions to transmission and distribution assets.
Other Income and Deductions
Interest and dividend income decreased for both the three- and six-month periods ended June 30, 2003, compared to
the same periods in 2002, mainly due to lower interest income from a lower PROACT balance. The six-month period
decrease also reflects lower interest income from lower average cash balances and lower interest rates.
Other nonoperating income increased for both the three- and six-month periods ended June 30, 2003, compared to
the same periods in 2002. The increases were mainly due to SCE's recognition of performance rewards related to
the Palo Verde Nuclear Generating Station (Palo Verde) approved by the CPUC during second quarter 2003. The
six-month increase also reflects SCE's accrual of 2002
Page 16
performance-based ratemaking (PBR) revenue under the PBR sharing mechanism filed with the CPUC during first
quarter 2003.
Interest expense - net of amounts capitalized decreased for the six-month period ended June 30, 2003, compared to
the same period in 2002, primarily due to lower interest expense related to the suspension of payments for
purchased power during 2001 and early 2002. These obligations were paid in March 2002. In addition, the
decrease was due to lower interest expense resulting from lower short-term and long-term debt balances and lower
interest rates.
Other nonoperating deductions increased for the year-to-date period ended June 30, 2003, mainly due to accruals
for regulatory matters.
Income Taxes
Income taxes decreased for both the three- and six-month periods ended June 30, 2003, compared to the same
periods in 2002, primarily due to a decrease in pre-tax income, partially offset by a reduction in SCE's tax
expense in 2002 related to the income tax benefit associated with the reestablishment of generation-related
regulatory assets upon implementation of the URG decision.
SCE's composite federal and state statutory rate was approximately 40.5% for both periods presented. The lower
effective tax rate of 39% and 37% realized in the three- and six-month periods, respectively, was primarily due
to state tax adjustments and offsetting property related flow-through taxes.
FINANCIAL CONDITION
Cash Flows from Operating Activities
Net cash provided by operating activities was $1.4 billion for the six-month period ended June 30, 2003 and $747
million for the same period in 2002.
The change in cash provided (used) by operating activities from continuing operations was mainly due to SCE's
March 2002 repayment of past-due obligations, partially offset by lower accrued interest and taxes in 2003 as
compared to 2002. The change was also due to timing of cash receipts and disbursements related to working
capital items.
Cash Flows from Financing Activities
Net cash used by financing activities was $868 million for the six-month period ended June 30, 2003, and
$1.4 billion for the comparable period in 2002.
During the six-month period ended June 30, 2003, SCE repaid $300 million of a one-year term loan due March 3,
2003, and $300 million on its revolving line of credit, both of which were part of the $1.6 billion financing
that took place in the first quarter of 2002. In addition, SCE repaid $125 million of its 6.25% first and
refunding mortgage bonds.
During the six-month period ended June 30, 2002, SCE repaid $531 million of commercial paper, $400 million of its
maturing principal on its senior unsecured notes, and remarketed $196 million of the $550 million of
pollution-control bonds repurchased during December 2000 and early 2001. Also during the first quarter of 2002,
SCE replaced the $1.65 billion credit facility with a $1.6 billion financing and made a payment of $50 million to
retire the remainder of the $1.65 billion credit facility.
Page 17
Cash Flows from Investing Activities
Cash flows from investing activities are affected by additions to property and plant, primarily for transmission
and distribution assets, and funding of nuclear decommissioning trusts. Additions to SCE's property and plant for
the six-month period ended June 30, 2003, were approximately $540 million, primarily for transmission and
distribution assets. Additions to SCE's property and plant for the comparable period in 2002 were approximately
$463 million, primarily for transmission and distribution assets.
Liquidity Issues
SCE expects to meet its continuing obligations in 2003 from cash and equivalents on hand and operating cash
flows. SCE had $994 million in cash and equivalents as of June 30, 2003.
In January 2002, the CPUC adopted a resolution implementing a settlement agreement with SCE. Based on the rights
to recover its past procurement-related costs, SCE repaid its undisputed past-due obligations and near-term debt
maturities in March 2002, using cash on hand resulting from the proceeds of the $1.6 billion credit facilities
and the remarketing of $196 million in pollution-control bonds. The $1.6 billion credit facilities included a
$600 million, one-year term loan due on March 3, 2003. SCE prepaid $300 million of this loan on August 14, 2002
and the remaining $300 million on February 11, 2003. The $1.6 billion credit facilities also included a $300
million revolving line of credit with a March 2004 maturity and a $700 million term loan with a March 2005 final
maturity. On April 16, 2003, SCE fully repaid the $300 million drawn under its revolving line of credit. Under
the term loan, net-cash proceeds from the issuance of capital stock or new indebtedness must be used to reduce
the term loan subject to certain exceptions.
On February 24, 2003, SCE completed an exchange offer for its 8.95% variable rate notes due November 2003. A
total of $966 million of these notes was exchanged for $966 million of a new series of first and refunding
mortgage bonds due February 2007. As a result of the exchange offer, SCE's remaining significant debt maturity
in 2003 is $34 million, comprising of the 8.95% variable rate notes due November 2003 that were not exchanged.
In addition, approximately $131 million of rate reduction notes are due in the remainder of 2003. These notes
have a separate cost recovery mechanism approved by state legislation and CPUC decisions.
SCE fully recovered the PROACT balance during July 2003. As a result of recovering the PROACT balance, SCE
implemented a CPUC approved customer rate-reduction plan effective August 1, 2003. The customer rate-reduction
plan reduces SCE's annual rates by $1.2 billion, but has no impact on earnings. See "Regulatory Matters--Other
Regulatory Matters--Customer Rate-Reduction Plan" for further details.
As of June 30, 2003, SCE's common equity to total capitalization ratio, for rate-making purposes, was
approximately 64%. The CPUC-authorized level is 48%. SCE expects to rebalance its capital structure to
CPUC-authorized levels in the future by paying dividends to its parent, Edison International, and issuing debt as
necessary. Factors that affect the amount and timing of such actions include, among other things, the outcome of
the pending appeal of the stipulated judgment approving SCE's settlement agreement with the CPUC (see "Regulatory
Matters--CPUC Litigation Settlement Agreement"), SCE's access to the capital markets and actions by the CPUC.
SCE resumed procurement of its residual net short (the amount of energy needed to serve SCE's customers from
sources other than its own generating plants, power purchase contracts and CDWR contracts) on January 1, 2003 and
as of June 30, 2003, has approximately $118 million posted as collateral to secure its obligations under power
purchase contracts and to transact through the ISO for imbalance power.
Page 18
SCE's liquidity may be affected by, among other things, matters described in "Regulatory Matters--CPUC Litigation
Settlement Agreement,--CDWR Power Purchases and Revenue Requirement Proceedings, and--Generation Procurement
Proceedings" sections.
COMMITMENTS
SCE's long-term debt maturities and sinking-fund requirements for the five twelve-month periods following June
30, 2003 are: 2004-- $281 million; 2005-- $1.3 billion; 2006-- $447 million; 2007-- $1.2 billion; and 2008--
$130 million. These amounts have been updated to reflect the $966 million exchange offer that took place on
February 24, 2003.
SCE has entered into six transition-capacity contracts during 2003, which contain capacity payment provisions.
SCE's commitments under these contracts for the five twelve-month periods following June 30, 2003 are: 2004--
$68 million; 2005-- $69 million; 2006-- $69 million; 2007-- $70 million; and 2008-- $37 million.
MARKET RISK EXPOSURES
SCE's primary market risk exposures include interest rate risk, generating fuel, commodity price and volume risk
and credit risk.
Interest Rate Risk
SCE is exposed to changes in interest rates primarily as a result of its borrowing and investing activities used
for liquidity purposes and to fund business operations, as well as to finance capital expenditures. The nature
and amount of SCE's long-term and short-term debt can be expected to vary as a result of future business
requirements, market conditions and other factors. In addition, SCE's authorized return on common equity is set
based on forecasts of interest rates and other factors.
Commodity Price and Volume Risk
Under the CPUC settlement agreement, SCE was permitted full recovery of its past procurement-related costs.
During July 2003, SCE completed recovery of these costs. Currently, SCE expects to recover its reasonable power
procurement costs in customer rates through regulatory mechanisms established by the CPUC. Assembly Bill (AB)
57, which the Governor of California signed in September 2002, provides that the CPUC shall adjust rates, or
order refunds, to amortize undercollections or overcollections of power procurement costs. Until January 1,
2006, the CPUC must adjust rates if the undercollection or overcollection exceeds 5% of SCE's prior year's
procurement costs, excluding revenue collected for CDWR. As a result of these regulatory mechanisms, changes in
energy prices may impact SCE's cash flows but are not expected to have an impact on earnings.
On January 1, 2003, SCE resumed procurement of its residual net short. SCE forecasts that its average 2003
residual net short, on an energy basis, will be approximately 4% of the total energy needed to serve SCE's
customers, with most of the short position occurring during off-peak hours and on weekends. Factors that could
cause SCE's residual net short to be larger than expected include: direct access customers returning to utility
service from their energy service provider; lower utility generation; lower deliveries from QFs, CDWR or
interutility contracts; and higher load requirements.
To reduce SCE's residual net short exposure, SCE entered into six transition capacity contracts with terms of up
to five years. Through fuel tolling arrangements, SCE is responsible for providing natural gas when the
underlying contract facilities are called upon to provide energy. SCE anticipates it will need to purchase
additional capacity and/or ancillary services to hedge its peak energy requirements.
Page 19
During 2004, SCE expects its residual net short to decline and its residual net long position to increase. SCE's
growing residual net long position arises from expected increases in deliveries under CDWR contracts allocated to
SCE's customers. In its 2004 procurement plan, under review by the CPUC, SCE has incorporated a price and volume
forecast from expected sales of residual net long power. If actual prices or volumes vary from forecast, SCE's
cash flow would be impacted. However, sales of residual power do not affect SCE's earnings.
Pursuant to CPUC decisions, SCE arranges for natural gas and related services for CDWR contracts allocated by the
CPUC to SCE. Financial and legal responsibility for the allocated contracts remains with CDWR. CDWR, through
the coordination of SCE, has hedged a portion of its expected natural gas requirements for certain contracts
allocated to SCE. To the extent the price of natural gas were to increase above the levels assumed for cost
recovery purposes, state law permits CDWR to recover its actual costs through rates established by the CPUC.
SCE purchases power from QFs CPUC state-mandated contracts. The contract energy price for most non-renewable QFs
is tied to the southern California border price of natural gas established on a monthly basis. During 2003, SCE
substantially hedged the risk of increasing natural gas prices. In its 2004 procurement plan, SCE has requested
CPUC authority to hedge its QF natural gas price risk. A decision on SCE's procurement plan is not expected
until late 2003.
Credit Risks
Credit risk arises primarily due to the chance that a counterparty will not perform as agreed under various
purchase and sale contracts or pay SCE for energy products delivered. SCE uses a variety of techniques to
mitigate its exposure to credit risk. These include restricting unsecured exposures to highly rated entities and
securing collateral from all others whenever possible. Such collateral may take many forms including cash from
the counterparty itself, payment guarantees or letters of credit from highly rated entities, and making purchases
from the counterparty which act to offset sales. SCE has established a risk management committee which regularly
reviews procurement credit exposure and approves credit limits for transacting with counterparties. Despite
these efforts, there can be no assurance that SCE's actions to mitigate credit risk will be wholly successful or
that collateral pledged will be adequate. SCE believes that any losses which may occur, despite prudent credit
management practices, should be fully recoverable from ratepayers if SCE follows the credit limits established in
its CPUC-approved procurement plan.
REGULATORY MATTERS
This section of MD&A presents updates to regulatory matters using three main subsections: generation and power
procurement, transmission and distribution, and other regulatory matters.
Generation and Power Procurement
CPUC Litigation Settlement Agreement
In 2001, SCE and the CPUC entered into a settlement of SCE's lawsuit against the CPUC, which sought a ruling that
SCE is entitled to full recovery of its past procurement-related costs. A key element of the settlement
agreement was the establishment of a $3.6 billion regulatory balancing account called the PROACT as of August 31,
2001. Other provisions of the settlement agreement are described in the "CPUC Litigation Settlement Agreement"
disclosure in the year-ended 2002 MD&A. TURN, a consumer advocacy group, and other parties appealed to the
federal court of appeals seeking to overturn the stipulated judgment of the district court that approved the
settlement agreement. On March 4, 2002, the United States Court of Appeals for the Ninth Circuit heard argument
on the appeal, and on
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September 23, 2002 the court issued its opinion. In its opinion, the federal court of appeals affirmed the
district court on all claims, with the exception of the challenges founded upon California state law, which the
appeals court referred to the California Supreme Court. In sum, the appeals court concluded that none of the
substantive arguments based on federal statutory or constitutional law compelled reversal of the district court's
approval of the stipulated judgment.
However, the appeals court stated in its opinion that there is a serious question whether the settlement
agreement violated state law, both in substance and in the procedure by which the CPUC agreed to it. The appeals
court added that if the settlement agreement violated state law, the CPUC lacked capacity to consent to the
stipulated judgment, and the stipulated judgment would need to be vacated. The appeals court indicated that, on
a substantive level, the stipulated judgment appears to violate California's electric industry restructuring
statute providing for a rate freeze. The appeals court also indicated that, on a procedural level, the
stipulated judgment appears to violate California laws requiring open meetings and public hearings. Because
federal courts are bound by the pronouncements of the state's highest court on applicable state law, and because
the federal appeals court found no controlling precedents from California courts on the issues of state law in
this case, the appeals court issued a separate order certifying those issues in question form to the California
Supreme Court and requested that the California Supreme Court accept certification.
The California Supreme Court accepted the certification, reformulated one of the certified questions as SCE had
requested, and set a briefing schedule. After the completion of the filing of briefs by the respective parties,
including supplemental briefs at the request of the California Supreme Court about an issue related to
California's open meeting laws, the parties made oral arguments before the California Supreme Court at a hearing
on May 27, 2003. SCE expects the California Supreme Court to issue its decision on the certified questions of
state law by August 25, 2003. Once the California Supreme Court issues its decision on the certified questions,
the matter will return to the Ninth Circuit for final disposition. In the meantime, the case is stayed in the
federal appellate court. SCE continues to operate under the settlement agreement. SCE continues to believe it
is probable that SCE's ultimate recovery of its past procurement costs through regulatory mechanisms, including
the PROACT, will be validated. However, SCE cannot predict with certainty the outcome of the pending legal
proceedings.
PROACT Regulatory Asset
In accordance with the settlement agreement and an implementing resolution adopted by the CPUC, in the fourth
quarter of 2001, SCE established the PROACT regulatory balancing account, with an initial balance of
approximately $3.6 billion reflecting the net amount of past procurement-related liabilities to be recovered by
SCE. Each month, SCE applied to the PROACT the positive or negative difference between SCE's revenue from retail
electric rates (including surcharges) and the costs that SCE is authorized by the CPUC to recover in retail
electric rates. The balance in the PROACT regulatory balancing account was $574 million at December 31, 2002 and
$84 million at June 30, 2003. At July 31, 2003, the PROACT regulatory balancing account was overcollected by
$148 million.
Under a settlement described in the "--Customer Rate-Reduction Plan," on July 15, 2003, SCE filed with the CPUC to
inform it of the forecast recovery of the PROACT balance in July 2003, to implement post-PROACT rate levels and
rate-making mechanisms effective August 1, 2003, and to transfer the PROACT overcollection to a new energy
resource recovery account (ERRA) regulatory balancing account on August 1, 2003. No other party filed protests
to SCE's filing within the required time and SCE expects approval of its filing by the CPUC.
CDWR Power Purchases and Revenue Requirement Proceedings
In accordance with an emergency order signed by the governor, CDWR began making emergency power purchases for
SCE's customers on January 17, 2001. Amounts SCE bills to and collects from its
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customers for electric power purchased and sold by CDWR are remitted directly to CDWR and are not recognized as
revenue by SCE. In February 2001, AB 1X (First Extraordinary Session, AB 1X) was enacted into law. AB 1X
authorized CDWR to enter into contracts to purchase electric power and sell power at cost directly to SCE's
retail customers, and authorized CDWR to issue bonds to finance electricity purchases. In addition, the CPUC is
responsible for allocating CDWR's revenue requirement among the customers of SCE, PG&E and SDG&E.
As discussed in the "CDWR Power Purchases and Revenue Requirement Proceedings" disclosure in the year-ended 2002
MD&A, the CPUC allocated to SCE's customers: $3.5 billion of total power procurement revenue requirement of $9
billion for 2001 and 2002; $331 million of the 2003 bond charge revenue requirement of $745 million; and
approximately $1.9 billion of the total 2003 power procurement revenue requirement of $4.3 billion. On July 1,
2003, CDWR submitted the supplemental determination of its 2003 power procurement revenue requirement to the
CPUC, reducing that revenue requirement by $1 billion, to $3.3 billion. SCE's customers' share of this reduction
is approximately $420 million if it is allocated by the CPUC in the same proportion that CDWR's original 2003
power procurement revenue requirement was allocated to them. SCE has requested that this $420 million be
retained by CDWR or, alternatively, used by SCE to partially offset an anticipated increase in CDWR's 2004 power
charge to SCE's customers. In September 2003, the CPUC is expected to issue a decision allocating the
supplemental determination among the investor-owned utilities.
In July 2003, CDWR released its proposed revenue requirement for 2004 that, if adopted, would establish a total
power procurement revenue requirement of $5.47 billion statewide, which includes a power charge of $4.65 billion
and a bond charge of $820 million. Comments on the proposed 2004 revenue requirement are due on August 14,
2003. Once CDWR adopts the 2004 revenue requirement, it will be submitted to the CPUC, which will allocate the
revenue requirement among the investor-owned utilities. Any increase or decrease in CDWR's bond and power
charges will be directly passed through to SCE's customers. The CPUC has not yet ruled on issues relating to the
true-up of CDWR's 2001-2002 revenue requirement and the allocation to each utility.
Direct Access Proceedings
Direct Access - Historical Procurement Charge
From 1998 through mid-September 2001, SCE's customers were able to choose to purchase power directly from an
energy service provider other than SCE (thus becoming direct access customers) or continue to purchase power from
SCE (customers who continue to purchase power from SCE are referred to as bundled service customers). On
March 21, 2002, in accordance with existing legislation directing the CPUC to select a date for the suspension of
the right of customers to purchase power from other energy service providers, the CPUC issued a final decision
affirming that new direct access arrangements entered into by SCE's customers after September 20, 2001 are
invalid. This decision did not affect direct access arrangements in place before that date. Direct access
customers receive a credit for the generation costs SCE saves by not serving them. Operating revenue is reported
net of this credit. Because of this credit, direct access power purchases resulted in additional undercollected
power procurement costs to SCE during 2000 and 2001. On July 17, 2002, the CPUC issued an interim decision to
establish a nonbypassable historical procurement charge requiring direct access customers to pay $391 million of
SCE's past power procurement costs. In a recent proposed decision, a CPUC administrative law judge (ALJ) approved a
petition for modification of the interim decision filed by SCE raising direct access customers' responsibility to
$473 million. The CPUC could adopt or reject this proposed decision in its final opinion. Several parties filed
petitions for review of the interim decision with the California Supreme Court. SCE has filed responses to the
petitions, but cannot predict with certainty the outcome of the petitions before the California Supreme Court.
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The historical procurement charge was initially set at 2.7(cent)per kWh, effective July 27, 2002. Subsequently, the
CPUC implemented an order establishing a surcharge for direct access customers' share of CDWR's costs, as
discussed in the paragraph below. Once that surcharge was implemented on January 1, 2003, the contribution by
direct access customers to the historical procurement charge was reduced from 2.7(cent)per kWh to 1(cent)per kWh for the
collection of the $391 million, with the remainder of the 2.7(cent)per kWh utilized for CDWR's costs associated with
direct access customers. Historical procurement charges recovered from direct access customers are used to
reduce SCE's generation rates to bundled service customers and have no impact on SCE's earnings.
Direct Access - Exit Fees
On November 7, 2002, the CPUC issued a decision assigning responsibility for a portion of energy crisis related
costs to direct access customers. The first category consists of CDWR's power procurement costs incurred between
January 17, 2001 and September 30, 2001. CDWR sold approximately $11 billion in bonds in fourth quarter 2002 to
finance a portion of the costs incurred during the California energy crisis. The CPUC decision stated that
direct access customers were responsible for paying a portion of CDWR bond charge to recover the principal and
financing costs associated with these bonds. The second category relates to CDWR's power procurement costs for
the fourth quarter of 2001 and the year 2002. The CPUC stated that direct access customers must pay a share of
these costs to make bundled service customers indifferent to suspension by the CPUC of the direct access program
on September 20, 2001. The third category includes CDWR long-term contract costs for 2003 and beyond. The CPUC
decision stated that a portion of these costs must be paid by direct access customers to keep bundled service
customers indifferent to the later suspension of direct access on the premise that CDWR signed some of its
long-term contracts with the expectation of serving the load that switched to direct access after July 1, 2001.
Finally, the last category relates to the above-market costs of SCE's utility retained generation (e.g., QFs
contract costs) that in accordance with AB 1890 are to be recovered from all customers on an ongoing basis. The
CPUC decision stated that: (1) the bond charge is applicable to all direct access customers except those who
were continuously on direct access and never used any CDWR power (less than 1% of SCE's load); (2) the next two
categories of costs are applicable to direct access customers who took bundled service at any time after
February 1, 2001; and (3) the last category is applicable to all direct access customers, including continuous
direct access customers.
On July 10, 2003, the CPUC issued a decision establishing a 2.7(cent)per kWh cap on the amount of exit fees to be
paid by direct access customers. The exact amount of exit fees to be paid by direct access customers will be
determined on an annual basis after CDWR submits its requested revenue requirement to the CPUC. On July 10,
2003, the CPUC ordered the imposition of exit fees (the Cost Responsibility Surcharges, or CRS) on so-called
"Municipal Departing Load," consumers who depart investor-owned utility service in favor of taking service from a
publicly-owned utility. That decision states that consumers switching to municipal service after February 1,
2001 will be responsible for paying CRS fees. The exact amount of the CRS obligation to be paid by direct access
customers will be determined by the end of 2003. Certain other parties have filed applications for rehearing of
this decision. See "--CDWR Power Purchases and Revenue Requirement Proceedings" for further discussion.
On April 3, 2003, in a separate decision, the CPUC adopted similar exit fees for customers who install onsite
generation facilities or arrange to purchase power from another entity that installs generation facilities on or
adjacent to their property. In its decision, the CPUC established three categories of customer generation. Each
category has varying exit fee responsibilities ranging from full exemption from the exit fees to full obligation
for all exit fees provided that the amount of customer generation installed statewide does not exceed CDWR's
forecast of customer generation it used when negotiating the long-term power contracts. The CPUC set an absolute
cap of 3,000 MW on eligible customer generation departing load through the life of CDWR's long-term contracts.
On April 17, 2003, SCE filed
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proposed tariff changes necessary to comply with the April 3, 2003 decision. The CPUC has not yet approved the
utilities' tariffs implementing the customer generation departing load exit fees.
Direct Access - Switching Exemptions
On May 8, 2003, the CPUC issued a decision establishing an exception to its March 21, 2002 decision (as discussed
in "--Historical Procurement Charge" section above) prohibiting new direct access arrangements after September 20,
2001. This exception, referred to as the "switching exemptions," permits direct access customers with a
pre-September 20, 2001 contract with an energy service provider to switch back and forth between bundled service
and direct access. In its May 8, 2003 decision, the CPUC adopted three specific exemptions:
o A "grandfathering" exemption that permits customers with pre-September 20, 2001 direct access contracts
who have already returned to bundled utility service subsequent to September 20, 2001 to return to direct
access during a 45-day transition period;
o A "safe harbor" exemption, under which direct access customers may return to bundled service on a
transitional basis while switching energy service providers. While in the safe harbor, these customers must
pay all incremental short-term power costs incurred on their behalf and the applicable direct access exit
fees; and
o A third exemption allows direct access customers who have returned to bundled service for a minimum
three-year period to thereafter depart again to acquire direct access service.
Direct access customers returning to bundled service for other than transition purposes must provide a six-month
advance notice and remain on bundled service for a minimum term of three years. Similarly, if a customer intends
to return to direct access after satisfying its three-year minimum stay on bundled service, it must provide
six-months advance notice. Direct access customers returning to bundled service remain responsible for their
share of direct access exit fees.
On June 23, 2003, SCE filed proposed tariff changes necessary to comply with the May 8, 2003 decision. Direct
access customers will continue to operate under current direct access provisions until the CPUC approves the
tariff changes, which is anticipated to occur in November 2003.
On July 9, 2003, SCE filed a petition with the California Supreme Court contending that the CPUC's May 8, 2003
decision is inconsistent with the state law which suspended the right of retail customers to acquire direct
access after the CPUC-determined date for suspension (September 20, 2001). TURN has also filed a petition with
the California Supreme Court raising similar arguments.
Temporary Surcharge
As discussed in the "Surcharge Decisions" disclosure in the year-ended 2002 MD&A, the CPUC allowed a continuation
of a 0.6(cent)-per-kWh temporary surcharge that was scheduled to terminate in June 2002 and required SCE to track the
associated revenue in a balancing account for rate-making purposes, until the CPUC determined the use of the
surcharge. A December 17, 2002 CPUC decision authorized SCE to use the revenue associated with the surcharge to
partially offset its higher 2003 revenue requirement. For financial reporting purposes, $187 million of
surcharge revenue, billed in the last six months of 2002, was credited to a regulatory liability account until it
could be used to offset SCE's higher 2003 procurement revenue requirement. This account was partially amortized
into revenue through July 31, 2003, with the remaining balance of $37 million transferred to the ERRA balancing
account as of August 1, 2003.
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Hedging Cost Recovery Decision
Pursuant to its authority mentioned in "--CPUC Litigation Settlement Agreement," SCE purchased $209 million in
hedging instruments (gas call options) in late 2001 to hedge a majority of its natural gas price exposure
associated with QF contracts for 2002 and 2003. A February 13, 2003 CPUC decision allowed SCE to transfer the
entire $209 million into the PROACT regulatory asset during first quarter 2003.
Generation Procurement Proceedings
The CPUC's Order Instituting Rulemaking, issued in October 2001, establishes the policies and mechanisms
necessary for SCE and the other major California electric utilities to resume power procurement as of January 1,
2003. In 2002, the CPUC issued four decisions: (1) on August 22, 2002, regarding transitional procurement
contracts; (2) on September 19, 2002, regarding the allocation of contracts previously entered into by CDWR among
the three major California utilities; (3) on October 24, 2002, for the resumption of power procurement activities
by these utilities on January 1, 2003, and adoption of a regulatory framework for such activities which includes
establishment of the ERRA regulatory balancing account to track fuel and purchased power authorized revenue
requirements against actual costs; and (4) on December 19, 2002, concerning SCE's short-term procurement plan for
2003. See the "Regulatory Matters--Generation Procurement Proceedings" in the year-ended 2002 MD&A for detailed
discussion of these matters. The CPUC recently issued five decisions on numerous applications for rehearing and
petitions for modifications filed on those decisions. The five decisions clarify some of the guidelines for
procuring power and provide mechanisms for a more objective determination of the reasonableness of procurement
costs for transactions outside an approved procurement plan, including the establishment of a precise amount
($37 million) on the annual maximum disallowance risk exposure for contract administration and least cost
dispatch.
California law and CPUC decisions provide for SCE to recover its reasonably incurred power procurement costs in
customer rates. A California statute adopted in 2002 allows SCE to recover reasonable procurement costs
recovered in compliance with an approved procurement plan. As discussed above, the CPUC determined that SCE's
maximum disallowance risk exposure for contract administration, including administration of allocated CDWR
contracts, and least cost dispatch is $37 million. Power purchases and sales not in compliance with the approved
procurement plan are subject to an expedited reasonableness review, and are not included in the disallowance cap
of $37 million.
On December 24, 2002 and January 14, 2003, SCE filed advice letters seeking CPUC approval of six renewable
contracts provisionally entered into by SCE pursuant to the August 22, 2002 decision on transitional procurement
contracts. The CPUC approved five of the six contracts. The sixth contract, which has not yet been approved,
will automatically terminate unless the time for obtaining CPUC approval is extended.
In accordance with the CPUC's October 24, 2002 decision, SCE filed its long-term resource plan on April 15,
2003. SCE's long-term resource plan included both a preferred plan and an interim plan. The preferred plan
contains long-term commitments that will encourage investment in new generation and transmission infrastructure,
increase long-term reliability and decrease price volatility. These commitments include:
o a significant increase in cost-effective energy efficiency and demand-response investments;
o renewable contracts that will meet or exceed the requirements of the Renewable Portfolio Standard (RPS),
(see below);
Page 25
o a substantial increment of new utility and third-party owned generation resources; and
o at least two new major transmission projects that will provide the state of California access to a
diverse set of generating resources and help facilitate a more competitive wholesale market.
The interim plan, by contrast, relies exclusively on new short- and medium-term contracts with no long-term
resource commitments (except for new renewable contracts). In its CPUC filing, SCE maintained that
implementation of its preferred plan requires resolution of various issues including: (1) stabilizing SCE's
customer base; (2) restoring SCE's investment-grade creditworthiness; (3) restructuring regulations regarding
energy efficiency and demand-response programs; (4) removing barriers to transmission development; (5) modifying
prior decisions, which impede long-term procurement; and (6) adopting a commercially realistic cost-recovery
framework that will enable utilities to obtain financing and enable contracting for new generation.
In accordance with the CPUC's October 24, 2002 decision, SCE filed its short-term resource plan on May 15, 2003.
The purpose of the short-term resource plan is to set defined boundaries for per se reasonable transactions. It
incorporates elements required by recent California legislation and CPUC decisions. The short-term plan is
designed so that the following types of transactions are deemed reasonable:
o procurement of electrical energy to meet a residual net short requirement;
o sales of surplus electrical energy to eliminate any residual net long position;
o procurement of additional electrical capacity to meet the combination of SCE's peak-bundled load plus
the ISO's requirement for ancillary services;
o gas procurement for non-QFs generating resources under contract to SCE (including gas procurement for
new tolling contracts that are needed, but have yet to be obtained);
o transactions to hedge the risk of energy payments to QFs which are tied to the price of natural gas;
o procurement of services, such as electric transmission, gas transportation, and gas-storage services,
which are required to support the foregoing transactions; and
o any other energy sales transactions that become necessary when surplus conditions arise.
Hearings on the short-term plan and certain key issues in the long-term plan commenced on July 21, 2003. A
decision is expected before the end of the year.
Procurement of Renewable Resources
As described in the year-ended 2002 MD&A, Senate Bill (SB) 1078 was signed into law in September 2002 and
provides for SCE and other California utilities to increase their procurement of renewable resources. Pursuant
to a ruling of the CPUC's assigned ALJ, issues related to implementation of RPS issues in SB 1078
are being determined on a separate, expedited schedule. Testimony on the implementation of SB 1078
was filed and hearings were held in April 2003. On June 23, 2003, the CPUC issued its preliminary decision on
RPS issues. The decision addressed implementation of various facets of SB 1078, including preliminary rules for
adopting a market price of electricity, against which bids in solicitations for renewable power are to be judged;
preliminary criteria for the rank ordering and selection of "least-cost" and "best-fit" renewable resources;
preliminary rules for "flexible compliance" with RPS procurement targets, and the adoption of standard terms and
Page 26
conditions for contracts to be entered into as part of the RPS process. The preliminary decision provides that
the parties will initially be given an opportunity, through workshops to be arranged by the CPUC and California
Energy Commission staff to agree on standard contract terms. With respect to compliance with procurement
targets, the CPUC preliminarily determined that up-front, automatic penalties in the amount of 5(cent)per kWh for
every kWh that falls below each utility's annual targets (subject to exceptions set forth in the decision), with
an annual penalty cap of $25 million, would be assessed against utilities that fail to comply with procurement
targets. The decision provides that noncreditworthy utilities are exempt from procurement, but that procurement
targets for such entities will nevertheless accrue during periods of noncreditworthiness and must be achieved,
subject to the flexible compliance rules, if and when the utility becomes creditworthy. The decision
contemplates additional proceedings in which the preliminary RPS implementation rules will be further developed.
On July 23, 2003, SCE applied for rehearing of the CPUC's June 23, 2003 decision, on the grounds, among others,
that the imposition of up-front, automatic penalties is contrary to legislative intent and deprives SCE of due
process, that the CPUC violated the RPS statute and federal law in establishing a capacity price for non-firm
products and that the CPUC proposed methodology for determining the market price of electricity effectively
excludes broker quotes and other recognized sources of market price information. If, within sixty days, the CPUC
either denies or fails to act on the application, SCE can seek review of the underlying decision in the
California Court of Appeal.
CDWR Contracts
On December 19, 2002, the CPUC adopted an operating order under which SCE, PG&E and SDG&E perform the
operational, dispatch, and administrative functions for CDWR's long-term power purchase contracts, beginning
January 1, 2003. The operating order sets forth the terms and conditions under which the three utility companies
administer CDWR contracts and requires the utility companies to dispatch all the generating assets within their
portfolios on a least-cost basis for the benefit of their ratepayers. PG&E and SDG&E filed an emergency motion
in which they sought to substitute their negotiated operating agreements with CDWR for the CPUC's operating
order. In March 2003, the CPUC approved the negotiated operating agreements with CDWR submitted by PG&E and
SDG&E, subject to certain modifications. Those modifications included eliminating provisions which would permit
termination of the agreements by the utilities, a provision which would permit additional guidance from CDWR as
to the performance of the utilities' obligations, a provision which would permit the direct collection from CDWR
of fees for administering CDWR contracts and certain other provisions that permit CDWR to direct the actions of
the utilities under the contracts. The decision also required SCE, PG&E and SDG&E to file gas supply plans for
the purchase of natural gas for CDWR contracts allocated to the utilities by April 17, 2003, and subsequent plans
every six months thereafter for the term of the operating order. SCE's gas supply plan was filed on April 18,
2003.
The CPUC also approved amendments to the servicing agreements between the utilities and CDWR relating to
transmission, distribution, billing, and collection services for CDWR's purchased power. The servicing order
issued by the CPUC identifies the formulas and mechanisms to be used by SCE to remit to CDWR the revenue
collected from SCE's customers for their use of energy from CDWR contracts that have been allocated to SCE.
Mohave Generating Station Proceeding
As discussed in the "Mohave Generating Station Proceeding" disclosure in the year-ended 2002 MD&A, on May 17,
2002, SCE filed with the CPUC an application to address certain issues (mainly coal and slurry-water supply
issues) facing the future extended operation of Mohave. The uncertainty over a post-2005 coal and water supply
has prevented SCE and other Mohave co-owners from starting to make approximately $1.1 billion (SCE's share is
$605 million) of Mohave-related investments if Mohave's operations are to be extended past 2005. The CPUC issued
a ruling on January 7, 2003 requesting further written testimony on specified issues related to Mohave and its
coal and slurry-water supply
Page 27
issues to determine whether it is in the public interest to extend Mohave operations post 2005. SCE submitted
supplemental testimony on January 30, 2003 stating, among other things, that the currently available information
is not sufficient for the CPUC to make such a determination at this time.
Several further rounds of testimony and other filings have been submitted in 2003 by SCE and the other parties in
the proceeding, most recently on July 1, 2003. The Navajo Nation and Hopi Tribe and the coal mining company,
Peabody Western Coal Company, currently take the position that the CPUC should, among other things, require SCE
to fund a study of a possible alternative water supply, and require SCE to commence a CPUC proceeding for
authorization of the Mohave pollution controls and other plant investments. Certain other parties have taken the
position that SCE should be authorized to prepare for a year-end 2005 shutdown of Mohave. To date there has been
no substantive decision by the CPUC, and it is possible that further written filings or hearings will be
required. Negotiations also have continued among the relevant parties in an effort to resolve the coal and water
supply issues, so far without any resolution.
Transmission and Distribution
2003 General Rate Case Proceeding
On May 3, 2002, SCE filed its formal application for the 2003 General Rate Case (GRC), requesting an increase of
$286 million over currently authorized revenue. The requested revenue increase is primarily related to capital
additions, updated depreciation costs and projected increases in pension and benefit expenses. In October 2002,
the CPUC's Office of Ratepayer Advocates issued its testimony and recommended a $172 million decrease in SCE's
current base rates, some $458 million below SCE's GRC request. Several other intervenors have also proposed
further reductions to SCE's request or have made other substantive proposals regarding SCE's operations.
Evidentiary hearings were concluded in March 2003, and opening briefs and reply briefs have been filed. During
the course of this GRC, SCE has agreed to a series of revisions to its request that would reduce its GRC increase
to $251 million, if authorized by the CPUC. SCE's 2004 request is an increase of $137 million over the 2003 GRC
request; however, it results in an overall non-fuel revenue reduction of $54 million, primarily due to the
expiration of the eight-year San Onofre incremental cost incentive pricing mechanism and the return of its
incremental costs to conventional cost-of-service rate-making on January 1, 2004. SCE's GRC filing also requests
an $85 million increase in revenue in 2005. The expiration of the incremental cost incentive pricing mechanism
on December 31, 2003, is expected to decrease SCE's 2004 earnings by approximately $100 million. A final
decision on Phase 1 issues is expected in the fourth quarter of 2003.
After SCE filed its application, the CPUC's Office of Ratepayer Advocates requested and was granted a three-month
extension to submit its testimony. This had the effect of deferring the other procedural milestones by three
months, including the expected date for a final decision. In response to the extension of the proceeding
schedule, SCE filed a motion requesting authorization to establish an account tracking SCE's requested revenue
requirement during the period between May 22, 2003 (the date a final decision would have been rendered under the
CPUC's Rate Case Plan) and the date a final decision is adopted. The amounts tracked in the memorandum account
would be subject to recovery or refund depending on the final outcome of the proceeding. On May 22, 2003, the
CPUC approved SCE's request to establish a memorandum account; accordingly the final revenue requirement approved
in the final decision will be effective May 22, 2003.
Phase 2 of the GRC proceeding will address revenue allocation and rate design issues. Hearings on this phase are
scheduled to begin in October 2003.
As part of the response to the September 11, 2001 terrorist attacks, on April 29, 2003, the Nuclear Regulatory
Commission issued further orders applicable to all commercial nuclear plant operators (including SCE's San
Onofre) regarding security Design Basis Threat (DBT), work hour rules for
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security personnel and training and fitness requirements for security personnel. SCE estimates additional
capital expenditures of approximately $50 million to meet the revised DBT requirements. Because most of these
expenditures fall outside test year 2003, but will be incurred during the three-year GRC cycle, on July 15, 2003,
SCE requested that the CPUC open a third phase of the GRC to consider SCE's request to track these
nuclear-related costs in a memorandum account effective January 1, 2004, for future cost recovery in 2005.
Cost of Capital Filing
SCE's annual cost of capital applications with the CPUC are required to be filed by May 8 of each year, with
decisions rendered in such proceedings becoming effective January 1 of the following year. On April 1, 2003, SCE
filed a petition with the CPUC seeking to eliminate the 2004 proceeding. This would result in SCE's 2003 cost of
capital decision, issued on November 7, 2002, remaining in effect throughout 2004. The CPUC has granted a
temporary extension of SCE's filing deadline to September 8, 2003 while it considers SCE's request. On April 24,
2003, the CPUC's Office of Ratepayer Advocates filed a response to SCE's petition supporting SCE's request for
eliminating the 2004 proceeding. The CPUC has issued two draft decisions on this matter. One decision would
approve SCE's request to defer the 2004 cost of capital proceeding and maintain its return on equity at its
current 11.6% level. The other would deny SCE's petition and order it to file an application to set its 2004
cost of capital. A final CPUC decision on this matter is expected in the third quarter of 2003.
Electric Line Maintenance Practices Proceeding
In August 2001, the CPUC issued an Order Instituting Investigation (OII) regarding SCE's overhead and underground
electric line maintenance practices. The order was based on a report issued by the CPUC's Consumer Protection
and Safety Division (CPSD), which alleged a pattern of noncompliance with the CPUC's general orders for the
maintenance of electric lines over the period 1998-2000. The order also alleged that noncompliant conditions
were involved in 37 accidents resulting in death, serious injury or property damage. The CPSD identified 4,817
alleged violations of the general orders during the three-year period; and the order put SCE on notice that it
could be subject to a penalty of between $500 and $20,000 for each violation or accident. In its opening brief
on October 21, 2002, the CPSD recommended that SCE be assessed a penalty of $97 million.
On June 19, 2003, a CPUC ALJ issued a presiding officer's decision (POD) fining SCE $576,000 for alleged
violations involving death, injury or property damage, failure to identify unsafe conditions or exceeding
required inspection intervals. The POD imposes no fines for over 98% of the alleged violations and does not find
that any of the alleged violations compromised the integrity or safety of SCE's electric system or were excessive
compared to other utilities. The POD orders SCE to consult with the CPSD and refine SCE's maintenance priority
system consistent with the discussion in the POD. On July 21, 2003, SCE filed an appeal opposing the POD's
interpretation that all general order non-conformances are violations subject to potential penalty. The CPSD
also filed an appeal, challenging the fact that the POD did not, in fact, penalize SCE for the 4,721 violations
alleged by CPSD in the OII. SCE, PG&E, SDG&E and the California Cable and Telecommunications Association filed
responses challenging the CPSD's appeal. The CPSD filed a response objecting to the intervention and appeals of
PG&E, SDG&E and the California Cable and Telecommunications Association.
Transmission Rate Case
In July 2000, the FERC issued a decision in SCE's 1998 transmission rate case in which it ordered a reduction of
approximately $38 million to SCE's requested annual transmission revenue requirement of $213 million.
Approximately $24 million of the ordered reduction was associated with the FERC's rejection of SCE's proposed
method for allocating overhead costs to transmission operations. In August 2000, SCE filed for rehearing of the
FERC decision, asking for reconsideration of its decision, assuming
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that the CPUC does not allow SCE to recover the $24 million in CPUC jurisdictional rates. SCE continued to
collect the $24 million annually in FERC rates subject to refund until new transmission rates became effective on
September 1, 2002. In February 2001, SCE filed with the CPUC a request to recover in CPUC rates the overhead
costs not permitted in FERC rates (amounting to $119 million as of June 30, 2003). On May 6, 2003, the assigned
CPUC ALJ issued a proposed decision rejecting the request. SCE filed comments challenging the proposed decision
on the grounds that the costs at issue were already found to be reasonable by the CPUC in SCE's 1995 general rate
case, and SCE is being denied the recovery of these costs solely due to different methodologies employed by the
CPUC and the FERC for allocation of overhead costs which are not directly assignable to the transmission and
distribution functions. On August 7, 2003, a CPUC commissioner issued an alternate decision approving SCE's
request to recover the overhead costs. Comments are due on the alternate draft decision on August 14, 2003, with
reply comments due August 18, 2003. A final CPUC decision on this matter is expected in the third quarter of
2003.
Wholesale Electricity and Gas Markets
In response to a consolidated proceeding related to the justness and reasonableness of rates charged by sellers
in the California Power Exchange and ISO markets as described in the "Regulatory Matters--Wholesale Electricity
Markets" disclosure in the year-ended 2002 MD&A, the FERC issued orders that initiated procedures for determining
additional refunds arising from market manipulation by energy suppliers. A FERC staff report issued on March 26,
2003, found that there was pervasive gaming and market manipulation of the electric and gas markets in California
and in the west coast and also described many of the techniques and effects of electric and gas market
manipulation. In a March 26, 2003 order, clarified on April 22, 2003, the FERC adopted a recommendation of the
FERC staff's final report to modify the ALJ's initial decision of December 12, 2002 to reflect the fact that the
gas indices used in the market manipulation formula overstated the cost of gas used to generate electricity. SCE,
as a member of the California parties, sought rehearing of the March 26 and April 22 orders. On June 25, 2003,
the FERC issued two sets of enforcement orders. The first set orders 54 entities, including SCE, to show cause
concerning gaming or anomalous market behavior during the period January 1, 2001 to June 20, 2001. The second
set orders 25 entities to show cause concerning gaming and anomalous market behavior in concert with Enron
entities. Under both sets of orders, the remedy for tariff violations will be the disgorgement of unjust profits
and possibly other non-monetary remedies. On June 25, 2003, the FERC also opened a new investigation into
anomalous bidding behavior during the period May 1, 2000 to October 2, 2000, focused primarily on economic
withholding by bidding above $250/MWh with disgorgement of profits as the possible penalty. SCE cannot, at this
time, determine the timing or amount of any potential refunds. Under the settlement agreement with the CPUC, 90%
of any refunds will be given to ratepayers and 10% would be given to shareholders. The CPUC issued an order
instituting rulemaking on July 10, 2003, to account for the consideration received by regulated gas and electric
utilities under a settlement with El Paso Natural Gas Company, et al. Under the terms of the rulemaking, SCE
will refund amounts (net of legal and consulting costs) through its ERRA balancing account as they are received
from El Paso under the terms of the settlement. In addition, amounts El Paso refunds to CDWR will result in
equivalent reductions in CDWR's revenue requirement from SCE ratepayers.
Other Regulatory Matters
Bark Beetle Proceeding
On March 7, 2003, the Governor of California issued a proclamation declaring a state of emergency in Riverside,
San Bernardino and San Diego counties where an infestation of bark beetles has created the potential for
catastrophic forest fires. The proclamation requested that the CPUC direct utilities with transmission lines in
these three counties to ensure that all dead, dying and diseased trees and vegetation are completely cleared from
their utility rights-of-way to mitigate the potential fire damage. The CPUC has authorized SCE to offset its
incremental expenses associated with the bark beetle emergency in a
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regulatory balancing account called the Catastrophic Event Memorandum Account (CEMA). SCE estimates that it will
incur in excess of $100 million in incremental expenses over the next several years, and anticipates that the
expected CEMA undercollection will be recovered in future rates with no impact on earnings.
Customer Rate-Reduction Plan
On January 17, 2003, SCE filed with the CPUC a detailed plan outlining how customer rates could be reduced later
in 2003 when SCE completed recovery of uncollected procurement costs incurred on behalf of its customers during
the California energy crisis and reflected in the PROACT. In its January 17, 2003 filing, SCE proposed that the
CPUC apply rate reductions of about $1.2 billion in the same manner it applied a series of rate surcharges during
the energy crisis in 2001.
On July 10, 2003, a CPUC decision reduced SCE's annual rates by $1.2 billion, beginning the month after the
PROACT balance was forecasted to be fully recovered. The decision approves an April 2003 settlement agreement
between SCE and active parties in this proceeding in which bills will be reduced by 8% for residential customers,
18% for small businesses, 13% for medium businesses and 19% for large businesses. In accordance with the
settlement agreement, on July 15, 2003, SCE submitted an advice filing to the CPUC to implement the rate
reduction effective on August 1, 2003, and to transfer the July 31, 2003 balance in the PROACT account (a $148
million overcollection) and the temporary surcharge balancing account (a $37 million overcollection) to the ERRA
regulatory balancing account.
OTHER DEVELOPMENTS
Clean Air Act
A federal court ruled on August 7, 2003 that Ohio Edison Company violated the Clean Air Act by upgrading seven
aging coal-fired power plants located at one site without first obtaining the necessary preconstruction permits
under the new source review program. This decision is currently being reviewed by SCE to assess what
implications, if any, the decision would have on SCE's results of operations or financial position.
Employee Compensation and Benefit Plans
On July 31, 2003, the United States District Court for the Southern District of Illinois held that the formula
used in IBM's cash balance pension plan violated the age discrimination provisions of the Employee Retirement
Income Security Act of 1974. The formula for SCE cash balance pension plan does not meet the standard set forth
in that District Court's decision. The IBM decision, however, conflicts with the decisions from two other
district courts and with the proposed regulations for cash balance plans issued by the IRS in December 2002. IBM
has announced that they will appeal the decision to the Seventh Circuit Court of Appeals. The effect of the IBM
decision on SCE's cash balance plan cannot be determined at this time.
Palo Verde Steam Generators
During the fall of 2003, Palo Verde Unit 2 steam generators are scheduled to be replaced. In addition, the Palo
Verde owners have approved the manufacturing of two additional sets of steam generators for installation in
Units 1 and 3. The Palo Verde owners expect that these steam generators will be installed in Units 1 and 3 in the
2005 to 2008 time frame. SCE's share of the costs of manufacturing and installing all replacement steam
generators at Palo Verde is approximately $106 million, and is expected to be recovered through the ratemaking
process.
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San Onofre Steam Generators
Like other nuclear power plants with steam generators made of a certain alloy (Inconel 600 mill annealed alloy),
San Onofre Units 2 and 3 have experienced degradation in their steam generators. Presently, 9% and 7%,
respectively, of the tubes in the existing steam generators of Unit 2 and Unit 3 have been plugged and removed
from service. SCE presently estimates that the San Onofre Units 2 and 3 generator design allows for the plugging
and removal from service of 21.4% of the tubes before the units must be shutdown or the steam generators
replaced. Industry experience is that the percentage of tubes requiring plugging accelerates as steam generators
made of this alloy age. Based on this industry experience, SCE has determined that the existing San Onofre
Units 2 and 3 steam generators may not be adequate to permit continued operation beyond the fuel cycle 16
refueling outages in 2009-2010. SCE and its co-owners at San Onofre Units 2 and 3 continue to evaluate the
necessity of replacing the steam generators and the cost-effectiveness of so doing.
ACQUISITIONS AND DISPOSITIONS
On July 17, 2003, SCE signed an option agreement with Sequoia Generating LLC (Sequoia), a subsidiary of InterGen,
to acquire Mountainview Power Company LLC, the owner of a new power plant currently being developed in Redlands,
California. This acquisition requires regulatory approval from both the CPUC and the FERC. SCE has filed an
application with the CPUC proposing a power-purchase agreement between SCE and Mountainview Power Company LLC.
If approved by the CPUC, SCE will seek FERC approval of the power-purchase agreement. SCE does not expect to
exercise the option without CPUC and FERC approvals. The option must be exercised prior to February 29, 2004.
If SCE exercises the option, SCE would recommence full construction of the project. Under the option agreement,
Sequoia may elect to terminate the option agreement at any time prior to SCE's exercise of the option. In such
event, Sequoia must return all previously tendered option payments.
On July 10, 2003, the CPUC approved a joint application filed by SCE and Pacific Terminals LLC, requesting
authorization for the sale of certain oil storage and pipeline facilities by SCE to Pacific Terminals for $158
million. The sale closed on July 31, 2003, and resulted in a $45 million after-tax gain to shareholders, to be
recorded in the third quarter of 2003.
NEW ACCOUNTING STANDARDS
Effective January 1, 2003, SCE adopted a new accounting standard, Accounting for Asset Retirement Obligations,
which requires entities to record the fair value of a liability for a legal asset retirement obligation in the
period in which it is incurred. When the liability is initially recorded, the entity capitalizes the cost by
increasing the carrying amount of the related long-lived asset. Over time, the liability is increased to its
present value each period, and the capitalized cost is depreciated over the useful life of the related asset.
Upon settlement of the liability, an entity either settles the obligation for its recorded amount or incurs a
gain or loss upon settlement. However, rate-regulated entities may recognize regulatory assets or liabilities as
a result of timing differences between the recognition of costs as recorded in accordance with this standard and
the recovery of costs through the rate-making process. Regulatory assets and liabilities may also be recorded if
it is probable that the asset retirement obligation (ARO) will be recovered through the rate-making process.
SCE's impact of adopting this standard was:
o SCE adjusted its nuclear decommissioning obligation to reflect the fair value of decommissioning its
nuclear power facilities. SCE also recognized AROs associated with the decommissioning of coal-fired
generation assets.
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o At December 31, 2002, SCE had accrued $2.3 billion to decommission its nuclear facilities and
$12 million to decommission its share of a coal-fired generating plant, under accounting principles in effect
at that time. Of these amounts, $298 million to decommission its inactive nuclear facility was recorded in
other long-term liabilities, and the remaining $2.0 billion was recorded as a component of the accumulated
provision for depreciation and decommissioning on the consolidated balance sheets in the 2002 Annual Report.
o As of January 1, 2003, SCE reversed the $2.3 billion it had previously recorded for decommissioning,
recorded the fair value of its AROs of approximately $2.0 billion in the deferred credits and other
liabilities section of the balance sheet, and increased its unamortized nuclear investment by $303 million.
The cumulative effect of a change in accounting principle from unrecognized accretion expense and
adjustments to depreciation, decommissioning and amortization expense recorded to date was a $354 million
after-tax gain, which under accounting standards for rate-regulated enterprises was deferred as a regulatory
liability, partially offset by a $235 million deferred tax asset, as of January 1, 2003. Accretion and
depreciation expense resulting from the application of the new standard is expected to be approximately $143
million in 2003. This cost will reduce the regulatory liability, with no impact on earnings. As of June
30, 2003, SCE's ARO for its nuclear facilities totaled approximately $2.1 billion and its nuclear
decommissioning trust assets had a fair value of $2.3 billion. If the new standard had been in place on
January 1, 2002, SCE's ARO as of that date would have been $1.98 billion. Approximately $1.97 billion
collected through rates for cost of removal of plant assets not considered to be legal obligations remain in
accumulated depreciation and decommissioning.
A new accounting standard, Accounting for Certain Financial Instruments with Characteristics of both Liabilities
and Equity, was issued in May 2003 and requires issuers to classify certain freestanding financial instruments as
liabilities. These freestanding liabilities include mandatorily redeemable financial instruments, obligations to
repurchase the issuer's equity shares by transferring assets and certain obligations to issue a variable number
of shares. The standard is effective for SCE on July 1, 2003. Upon implementation, SCE will reclassify its
preferred stock subject to mandatory redemption to the liabilities section of its consolidated balance sheets.
This item is currently classified between liabilities and equity. In addition, dividend payments on these
instruments will be recorded as interest expense on SCE's consolidated statements of income. SCE is studying the
impact of the new standard but does not expect implementation of the new standard to have a material impact on
its financial statements.
FORWARD-LOOKING INFORMATION AND RISK FACTORS
In the preceding MD&A and elsewhere in this quarterly report, the words estimates, expects, anticipates,
believes, predict, and other similar expressions are intended to identify forward-looking information that
involves risks and uncertainties. Actual results or outcomes could differ materially from those anticipated.
Risks, uncertainties and other important factors that could cause results to differ, or that otherwise could
impact SCE, include, among other things:
o the outcome of the pending appeal of the stipulated judgment approving SCE's settlement agreement with
the CPUC, and the effects of other legal actions, if any, attempting to undermine the provisions of the
settlement agreement or otherwise adversely affecting SCE;
o changes in prices and availability of wholesale electricity, natural gas, other fuels, transmission
services, and other changes in operating costs, which could affect the timing of SCE's energy procurement
cost recovery or otherwise impact SCE's operations and financial results;
Page 33
o the effects of declining interest rates and investment returns on employee benefit plans and nuclear
decommissioning trusts;
o changing conditions in wholesale power markets, such as general credit constraints and thin trading
volumes, that could make it difficult for SCE to enter into hedging agreements;
o the actions of securities rating agencies, including the determination of whether or when to make
changes in SCE's credit ratings, the ability of SCE to regain investment-grade ratings, and the impact of
current or lowered ratings and other financial market conditions on the ability of SCE to obtain needed
financing on reasonable terms;
o actions by state and federal regulatory and administrative bodies setting rates, adopting or modifying
cost recovery, holding company rules, accounting and rate-setting mechanisms or otherwise changing the
regulatory and business environments within which SCE does business, as well as legislative or judicial
actions affecting the same matters;
o the effects of increased competition in energy-related businesses, including new market entrants and the
effects of new technologies that may be developed in the future;
o threatened attempts by municipalities within SCE's service territory to form public power entities
and/or acquire SCE's facilities for customers;
o new or increased environmental requirements that could require capital expenditures or otherwise affect
the operations and cost of SCE, and possible increased liabilities under new or existing requirements; and
o weather conditions, natural disasters, and other unforeseen events.
Page 34
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information responding to Item 3 is included in Item 2, Management's Discussion and Analysis of Results of
Operations and Financial Condition, under Market Risk Exposures, and is incorporated herein by reference.
Item 4. Controls and Procedures
Disclosure Controls and Procedures.
SCE's management, with the participation of the company's Chief Executive Officer and Chief Financial Officer,
has evaluated the effectiveness of SCE's disclosure controls and procedures (as such term is defined in Rules
13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the "Exchange Act")) as of the end
of the period covered by this report. Based on such evaluation, the Chief Executive Officer and Chief Financial
Officer have concluded that, as of the end of such period, SCE's disclosure controls and procedures are effective.
Internal Control Over Financial Reporting.
There have not been any changes in SCE's internal control over financial reporting (as such term is defined in
Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the fiscal quarter to which this report relates that
have materially affected, or are reasonably likely to materially affect, SCE's internal control over financial
reporting.
Page 35
PART II OTHER INFORMATION
Item 1. Legal Proceedings
CPUC Litigation Settlement Agreement
As previously reported in Part I, Item 3 of SCE's Annual Report on Form 10-K for the fiscal year ended December
31, 2002 (2002 Form 10-K), and in Part II, Item 1 of SCE's Quarterly Report on Form 10-Q for the period ending
March 31, 2003 (First Quarter 10-Q), SCE filed a lawsuit against the California Public Utilities Commission
(CPUC) in federal district court seeking a ruling that SCE is entitled to full recovery of its electricity
procurement costs incurred during the energy crisis in accordance with the tariffs filed with the Federal Energy
Regulatory Commission. See the discussion, which is incorporated herein by this reference, in Part 1, Item 2,
Management's Discussion and Analysis of Financial Condition and Results of Operations under "SCE'S REGULATORY
MATTERS - CPUC Litigation Settlement Agreement."
CPUC Investigation Regarding SCE's Electric Line Maintenance Practices
As previously reported in Part I, Item 3 of SCE's 2002 Form 10-K, and in Part II, Item 1 of SCE's First Quarter
10-Q, on August 25, 2001, the CPUC issued an order instituting investigation regarding SCE's overhead and
underground electric line maintenance practices. See the discussion, which is incorporated herein by this
reference, in Part 1, Item 2, Management's Discussion and Analysis of Financial Condition and Results of
Operations under "SCE'S REGULATORY MATTERS - Electric Line Maintenance Proceedings."
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Item 4. Submission of Matters to a Vote of Security Holders
At SCE's Annual Meeting of Shareholders on May 15, 2003, shareholders elected twelve nominees to the Board of
Directors. The number of broker non-votes for each nominee was zero. The numbers of votes cast for and withheld
from each Director-nominee were as follows:
Numbers of Votes
- ----------------------------------------------------------------------------------------------------------
Name For Withheld
- ----------------------------------------------------------------------------------------------------------
John E. Bryson 463,293,672 463,668
Alan J. Fohrer 463,299,264 458,076
Bradford M. Freeman 461,739,582 2,017,758
Joan C. Hanley 463,221,846 535,494
Bruce Karatz 463,278,876 478,464
Luis G. Nogales 463,265,028 492,312
Ronald L. Olson 463,294,668 462,672
James M. Rosser 463,067,128 690,212
Richard T. Schlosberg, III 461,733,552 2,023,788
Robert H. Smith 461,710,632 2,046,708
Thomas C. Sutton 461,929,970 1,827,370
Daniel M. Tellep 461,716,422 2,040,918
- ----------------------------------------------------------------------------------------------------------
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1 Certificate of Amendment and Restated Articles of Incorporation of SCE effective June 1, 1993
(File No. 1-2313, Form 10-K for the year ended December 31, 1993)*
3.2 Certificate of Correction of Restated Articles of Incorporation of SCE dated effective
August 21, 1997 (File No. 1-2313, Form 10-Q for the quarter ended September 30, 1997)*
3.3 Amended Bylaws of Southern California Edison Company as adopted by the Board of Directors on
January 1, 2003 (File No. 1-2313, Form 10-K for the year ended December 31, 2002)*
31.1 Certification of the Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act
31.2 Certification of the Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act
32 Statement Pursuant to 18 U.S.C. 1350
- ------------------
* Incorporated by reference pursuant to Rule 12b-32.
Page 37
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
-------------- ---------- ----------------
May 7, 2003 May 7, 2003 7 and 9
Page 38
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 12, 2003