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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 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 November 10, 2003
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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 Nine Months
Ended September 30, 2003 and 2002 1
Consolidated Statements of Comprehensive Income -
Three and Nine Months Ended September 30, 2003 and 2002 1
Consolidated Balance Sheets - September 30, 2003
and December 31, 2002 2
Consolidated Statements of Cash Flows -
Nine Months Ended September 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 17
Item 3. Quantitative and Qualitative Disclosures About Market Risk 41
Item 4. Controls and Procedures 41
Part II. Other Information:
Item 1. Legal Proceedings 42
Item 6. Exhibits and Reports on Form 8-K 44
Signatures
SOUTHERN CALIFORNIA EDISON COMPANY
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Nine Months Ended
September 30, September 30,
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In millions 2003 2002 2003 2002
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(Unaudited)
Operating revenue $ 2,794 $ 2,713 $ 6,994 $ 6,754
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Fuel 68 59 175 160
Purchased power 1,013 780 2,187 1,615
Provisions for regulatory adjustment clauses - net 332 738 1,141 1,052
Other operation and maintenance 516 474 1,473 1,410
Depreciation, decommissioning and amortization 215 189 603 578
Property and other taxes 42 27 125 83
Net gain on sale of utility plant (5) (6) (5) (6)
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Total operating expenses 2,181 2,261 5,699 4,892
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Operating income 613 452 1,295 1,862
Interest and dividend income 17 48 96 211
Other nonoperating income 20 9 68 28
Interest expense - net of amounts capitalized (108) (132) (346) (456)
Other nonoperating deductions (8) 16 (43) 7
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Income from continuing operations before tax 534 393 1,070 1,652
Income tax 203 155 411 562
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Income from continuing operations 331 238 659 1,090
Income from discontinued operations - net of tax 44 -- 50 --
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Net income 375 238 709 1,090
Dividends on preferred stock
subject to mandatory redemption -- 3 5 11
Dividends on preferred stock
not subject to mandatory redemption 1 1 4 4
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Net income available for common stock $ 374 $ 234 $ 700 $ 1,075
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Nine Months Ended
September 30, September 30,
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In millions 2003 2002 2003 2002
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(Unaudited)
Net income $ 375 $ 238 $ 709 $ 1,090
Other comprehensive income, net of tax:
Amortization of cash flow hedges 1 1 2 11
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Comprehensive income $ 376 $ 239 $ 711 $ 1,101
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The accompanying notes are an integral part of these financial statements.
Page 1
SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
In millions 2003 2002
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(Unaudited)
ASSETS
Cash and equivalents $ 1,670 $ 992
Restricted cash 62 47
Receivables, less allowances of $28 and $36
for uncollectible accounts at respective dates 828 767
Accrued unbilled revenue 546 437
Fuel inventory 10 12
Materials and supplies, at average cost 160 153
Accumulated deferred income taxes - net 99 42
Regulatory assets - net -- 509
Prepayments and other current assets 95 57
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Total current assets 3,470 3,016
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Nonutility property - less accumulated provision
for depreciation of $22 and $15 at respective dates 112 103
Nuclear decommissioning trusts 2,369 2,210
Other investments 279 214
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Total investments and other assets 2,760 2,527
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Utility plant, at original cost:
Transmission and distribution 14,602 14,202
Generation 1,362 1,348
Accumulated provision for depreciation and decommissioning (6,148) (7,990)
Construction work in progress 589 529
Nuclear fuel, at amortized cost 129 153
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Total utility plant 10,534 8,242
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Regulatory assets - net 2,971 3,838
Other deferred charges 520 629
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Total deferred charges 3,491 4,467
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Assets of discontinued operations -- 62
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Total assets $ 20,255 $ 18,314
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The accompanying notes are an integral part of these financial statements.
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SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED BALANCE SHEETS
September 30, December 31,
In millions, except share amounts 2003 2002
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(Unaudited)
LIABILITIES AND SHAREHOLDER'S EQUITY
Short-term debt $ -- $ --
Long-term debt due within one year 406 1,671
Preferred stock to be redeemed within one year 9 9
Accounts payable 840 745
Accrued taxes 956 699
Regulatory liabilities - net 322 --
Other current liabilities 1,500 1,439
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Total current liabilities 4,033 4,563
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Long-term debt 4,889 4,504
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Accumulated deferred income taxes - net 2,496 2,658
Accumulated deferred investment tax credits 142 148
Customer advances and other deferred credits 466 964
Power-purchase contracts 230 309
Preferred stock subject to mandatory redemption 141 --
Accumulated provision for pensions and benefits 392 356
Asset retirement obligations 2,078 --
Other long-term liabilities 167 152
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Total deferred credits and other liabilities 6,112 4,587
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Total liabilities 15,034 13,654
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Commitments and contingencies
(Notes 2 and 4)
Preferred stock subject to mandatory redemption -- 147
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Common stock (434,888,104 shares outstanding at each date) 2,168 2,168
Additional paid-in capital 346 340
Accumulated other comprehensive loss (14) (16)
Retained earnings 2,592 1,892
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Total common shareholder's equity 5,092 4,384
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Preferred stock not subject to mandatory redemption 129 129
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Total shareholders' equity 5,221 4,513
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Total liabilities and shareholders' equity $ 20,255 $ 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
Nine Months Ended
September 30,
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In millions 2003 2002
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(Unaudited)
Cash flows from operating activities:
Income from continuing operations $ 659 $ 1,090
Adjustments to reconcile to
net cash provided by operating activities:
Depreciation, decommissioning and amortization 603 578
Other amortization 76 78
Deferred income taxes and investment tax credits (168) (493)
Regulatory assets - long-term - net 414 1,003
Gas options 62 12
Power contracts collateral (76) --
Other assets 67 13
Other liabilities (292) 143
Changes in working capital:
Receivables and accrued unbilled revenue (170) (18)
Regulatory assets - short-term - net 792 70
Fuel inventory, materials and supplies (5) (6)
Prepayments and other current assets (54) (50)
Accrued interest and taxes 228 225
Accounts payable and other current liabilities 185 (2,354)
Operating cash flows from discontinued operations (34) --
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Net cash provided by operating activities 2,287 291
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Cash flows from financing activities:
Long-term debt issuance costs (11) (32)
Long-term debt repaid (729) (1,000)
Bonds remarketed and funds held in trust -- 191
Redemption of preferred stock (6) (100)
Rate reduction notes repaid (176) (176)
Nuclear fuel financing - net -- (59)
Short-term debt financing - net -- (527)
Dividends paid (9) (36)
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Net cash used by financing activities (931) (1,739)
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Cash flows from investing activities:
Additions to property and plant (820) (694)
Proceeds from sale of property 5 10
Net funding of nuclear decommissioning trusts (16) 1
Sales of investments in other assets 6 7
Investing cash flows from discontinued operations 147 --
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Net cash used by investing activities (678) (676)
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Net increase (decrease) in cash and equivalents 678 (2,124)
Cash and equivalents, beginning of period 992 3,414
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Cash and equivalents, end of period, continuing operations $ 1,670 $ 1,290
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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 September 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) Annual Report on Form
10-K for the year ended December 31, 2002 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 September 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 (ARO) 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 ARO will be recovered through the rate-making process.
SCE's impact of adopting this standard was:
o SCE adjusted its nuclear decommissioning obligation to reflect the fair value of decommissioning its
nuclear power facilities. SCE also recognized AROs associated with the decommissioning of coal-fired
generation assets.
o At December 31, 2002, SCE had accrued $2.3 billion to decommission its nuclear facilities and
$12 million to decommission its share of a coal-fired generating plant, under accounting principles in effect
at that time. Of these amounts, $298 million to decommission its inactive nuclear facility was recorded in
other long-term liabilities, and the remaining $2.0 billion was recorded as a component of the accumulated
provision for depreciation and decommissioning on the consolidated balance sheets in the 2002 Annual Report.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
o As of January 1, 2003, SCE reversed the $2.3 billion it had previously recorded for decommissioning,
recorded the fair value of its AROs of approximately $2.0 billion in the deferred credits and other
liabilities section of the balance sheet, and increased its unamortized nuclear investment by $303 million.
The cumulative effect of a change in accounting principle from unrecognized accretion expense and
adjustments to depreciation, decommissioning and amortization expense recorded to date was a $354 million
after-tax gain, which under accounting standards for rate-regulated enterprises was deferred as a regulatory
liability, partially offset by a $235 million deferred tax asset, as of January 1, 2003. Accretion and
depreciation expense resulting from the application of the new standard is expected to be approximately $143
million in 2003. This cost will reduce the regulatory liability, with no impact on earnings. As of
September 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 $2.4 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 $2.0 billion
collected through rates for cost of removal of plant assets not considered to be legal obligations remain in
accumulated depreciation and decommissioning.
Effective July 1, 2003, SCE adopted a new accounting standard, Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity, which required 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. Effective July 1, 2003, SCE reclassified its preferred stock subject to mandatory
redemption to the liabilities section of its consolidated balance sheet. This item was previously classified
between liabilities and equity. In addition, effective July 1, 2003, dividend payments on this instrument are
included in interest expense - net of amounts capitalized on SCE's consolidated statements of income. Prior
period financial statements are not permitted to be restated for these changes. Therefore, upon adoption there
was no cumulative impact incurred due to this accounting change. See disclosures regarding the preferred stock
in Note 3.
Page 6
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Regulatory Assets and Liabilities
Regulatory assets, less regulatory liabilities, included in the consolidated balance sheets are:
September 30, December 31,
In millions 2003 2002
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Current:
PROACT - net $ -- $ 574
Regulatory balancing accounts and other - net (322) (65)
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(322) 509
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Long-term:
Flow-through taxes - net 1,279 1,336
Rate reduction notes - transition cost deferral 1,015 1,215
Unamortized nuclear investment - net 520 630
Unamortized coal plant investment - net 69 61
Unamortized loss on reacquired debt 227 237
Environmental remediation 66 70
Asset retirement obligation (312) --
Regulatory balancing accounts and other - net 107 289
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2,971 3,838
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Total $ 2,649 $ 4,347
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SCE fully recovered the procurement-related obligations account (PROACT) balance during July 2003 and on August
1, 2003, transferred the PROACT overcollection to a new energy resource recovery account regulatory balancing
account. The new balancing account acts as a mechanism to recover SCE's fuel costs related to its generating
stations, purchased-power costs related to cogeneration and renewable contracts, existing interutility and
bilateral contracts that were entered into prior to January 17, 2001, and new procurement-related costs that SCE
began incurring on January 1, 2003, the date on which the California Public Utilities Commission (CPUC)
transferred back to SCE the responsibility for procuring energy resources for its customers.
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.
Page 7
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Three Months Ended Nine Months Ended
September 30, September 30,
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In millions 2003 2002 2003 2002
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Net income available for common stock, as reported $ 374 $ 234 $ 700 $ 1,075
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 1 1 3 2
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 2 1 4 2
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Pro forma net income available for common stock $ 373 $ 234 $ 699 $ 1,075
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Supplemental Cash Flows Information
Nine Months Ended
September 30,
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In millions 2003 2002
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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
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Cash paid on retirement of credit facility $ -- $ (50)
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Details of long-term debt exchange offer:
Variable rate notes redeemed $ (966) $ --
First and refunding bonds issued 966 --
Obligation to fund investment in acquisition $ 8 $ --
----------------------------------------------------------------------------------------------------------
Note 2. Regulatory Matters
Further information on regulatory matters, including proceedings for California Department of Water Resources
(CDWR) 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.
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. The Utility Reform Network (TURN), a consumer advocacy group, and other parties appealed to the United
States Court of Appeals for the Ninth Circuit seeking to overturn the stipulated judgment of the federal district court
that approved the settlement agreement. On September 23, 2002 the Ninth Circuit issued its opinion affirming the
federal district court on all claims, with the exception of the challenges founded upon California state law, which the
Ninth Circuit referred to the California Supreme Court.
Page 8
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
On August 21, 2003, the California Supreme Court issued its decision on the certified questions, concluding that
the settlement agreement did not violate California law in any of the respects raised by the Ninth Circuit.
Specifically, the California Supreme Court concluded that: the commissioners of the CPUC had the authority to
propose the stipulated judgment in light of the provisions of California's restructuring statute; the procedures
employed by the CPUC in entering the stipulated judgment did not violate California's open meeting law for public
agencies; and the stipulated judgment did not violate California's public utilities code by allegedly altering
rates without a public hearing and issuance of findings.
On September 8, 2003, TURN filed a petition for rehearing of the California Supreme Court's decision. On October
22, 2003, the California Supreme Court denied TURN's petition. The matter will now return to the Ninth Circuit
for final disposition, subject to any efforts by TURN to pursue further federal appeals. In the meantime, the
case is stayed in the federal appellate court. SCE continues to believe it is probable that recovery of its past
procurement costs through regulatory mechanisms, including the PROACT, ultimately will be validated. However,
SCE cannot predict with certainty the ultimate 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 (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
4,721 of the violations alleged by the CPSD in the OII. SCE, Pacific Gas and 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 reopened 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
Page 9
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 past 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 October 29, 2003. The Navajo Nation and Hopi Tribe and the coal mining company,
Peabody Western Coal Company, have taken 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. Negotiations have
continued among the relevant parties in an effort to resolve the coal and water supply issues, but no resolution
has been reached. On October 8, 2003, the CPUC indicated that when the CPUC is assured that resolution of the
coal and water supply issues is progressing, hearings on the costs and timelines for all alternatives would be
scheduled.
Wholesale Electricity and Gas Markets
In 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 Federal Energy Regulatory Commission
(FERC) issued orders in March 2003 that initiated procedures for determining
Page 10
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
additional refunds arising from market manipulation by energy suppliers. The 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 on 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 a FERC 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 sought rehearing of the March 26, 2003 and April 22, 2003 orders. On October 16, 2003, the FERC issued an
order on SCE's rehearing request, upholding its March 26, 2003 order. On June 25, 2003, the FERC issued two sets
of enforcement orders. The first set ordered 54 entities, including SCE, to show cause concerning gaming or
anomalous market behavior during the period January 1, 2001 to June 20, 2001. SCE has provided information to
the FERC staff demonstrating that it did not engage in gaming or anomalous market behavior, filed its response to
the show cause order on September 2, 2003, and worked with the FERC staff to resolve the issue. On November 3,
2003, the FERC staff filed a motion to dismiss the charges against SCE. The second set of enforcement orders
ordered 25 entities to show cause concerning gaming and anomalous market behavior in concert with Enron and other
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. Since these orders,
the FERC staff has filed numerous motions to dismiss against various respondents in the proceeding and has
entered into settlements with a number of respondents. SCE and other parties subject to the order have filed
dozens of opposition pleadings. 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 actually realized by SCE will be
refunded to ratepayers. On October 20, 2003, the CPUC issued a decision on the accounting and rate-making
mechanisms related to the consideration received by regulated gas and electric utilities under a settlement with
El Paso Natural Gas Company, and other parties. Based on this decision, SCE will refund to ratepayers amounts
(net of legal and consulting costs) through its energy resource recovery 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. Refunds from El Paso will not be
received until the proposed settlement is approved by the California Superior Court in San Diego County. A
hearing for approval of the proposed settlement is scheduled for November 20, 2003.
Note 3. Preferred Stock Subject to Mandatory Redemption
SCE has 12 million authorized shares of preferred stocks subject to mandatory redemption. All cumulative
preferred stocks are redeemable. Mandatorily redeemable preferred stocks are subject to sinking-fund
provisions. When preferred shares are redeemed, the premiums paid are charged to common equity.
SCE's preferred stock redemption requirements for the five twelve-month periods following September 30, 2003
are: 2004 - $9 million; 2005 - $9 million; 2006 - $9 million; 2007 - $9 million; and 2008 - $59 million.
Page 11
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE's cumulative preferred stocks subject to mandatory redemption consisted of:
September 30, December 31,
Dollars in millions, except per share amounts 2003 2002
-------------------------------------------------------------------------------------------------------------------
September 30, 2003
---------------------------
Shares Redemption
Outstanding Price
$100 par value:
6.05% Series 693,800 $ 100.00 $ 69 $ 75
7.23 807,000 100.00 81 81
Preferred stock to be redeemed within one year (9) (9)
-------------------------------------------------------------------------------------------------------------------
Total $ 141 $ 147
-------------------------------------------------------------------------------------------------------------------
In second quarter 2002, SCE redeemed 1,000,000 shares of 6.45% Series preferred stock. There were no other
redemptions, and no issuances, of preferred stock subject to mandatory redemption for the periods presented.
The 7.23% Series preferred stock has mandatory sinking funds, requiring SCE to redeem at least 50,000 shares per
year from 2002 through 2006, and 750,000 shares in 2007. However, SCE is allowed to credit previously
repurchased shares against the mandatory sinking fund provisions. Since SCE had previously repurchased 193,000
shares of this series, no shares were redeemed in 2002. At December 31, 2002, SCE had 143,000 of previously
repurchased, but not retired, shares available to credit against the mandatory sinking fund provisions.
Note 4. Contingencies
In addition to the matters disclosed in these Notes, SCE is involved in other legal, tax and regulatory
proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of
business. SCE believes the outcome of these other proceedings will not materially affect its results of
operations or liquidity.
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.
Page 12
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE's recorded estimated minimum liability to remediate its 30 identified sites is $89 million. In third quarter
2003, SCE sold certain oil storage and pipeline facilities. This sale caused a reduction in SCE's recorded
estimated minimum environmental liability. 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
$240 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 $31 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 $66 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 September 30, 2003 were $15 million.
Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the
upper limit of the estimated range for its identified sites and, based upon the CPUC's regulatory treatment of
environmental remediation costs, SCE believes that costs ultimately recorded will not materially affect its
results of operations or financial position. There can be no assurance, however, that future developments,
including additional information about existing sites or the identification of new sites, will not require
material revisions to such estimates.
Federal Income Taxes
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.
Page 13
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Mountainview Acquisition
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.
Navajo Nation Litigation
Peabody Holding Company (Peabody) supplies coal from mines on Navajo Nation lands to SCE's Mohave Generating
Station. 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 Federal 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 Federal 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
Federal Claims did have jurisdiction to award damages and remanded the case to the Court of Federal 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.
On October 24, 2003, the Court of Appeals, on remand from the Supreme Court, issued a decision remanding the
action brought against the Government back to the Court of Federal Claims for further proceedings. The Court of
Appeals, acting on a suggestion on remand filed by the Navajo Nation, held in its October 24, 2003 decision that
the Supreme Court's 2003 decision was focused on a particular statute and therefore did not address the question
of whether a network of other statutes, treaties and
Page 14
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
regulations imposed judicially enforceable fiduciary duties on the United States during the time period in
question. The Court of Appeals, however, further recognized the possibility that the Navajo Nation may have
waived the right to assert claims based on the network theory. The Court of Appeals accordingly directed in its
remand order that the Court of Federal Claims decide in the first instance whether such a waiver had occurred.
If no waiver is found, then the Court of Federal Claims is directed in the remand order to determine whether a
network of other statutes and regulations imposes an enforceable fiduciary obligation on the Government and, if
so, whether such duties were breached under the relevant facts. SCE is currently analyzing the extent to which
the Court of Appeals' October 24, 2003 decision will have any impact on the Navajo Nation's claims against SCE
and Peabody.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, nor the impact
on this complaint or the Supreme Court's decision on the outcome of the Navajo Nation's suit against the
Government, or the impact of the complaint on the operation of Mohave beyond 2005.
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $10.9 billion. SCE and other owners of the
San Onofre and Palo Verde Nuclear Generating Stations have purchased the maximum private primary insurance
available ($300 million). The balance is covered by the industry's retrospective rating plan that uses deferred
premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the U.S. results in
claims and/or costs which exceed the primary insurance at that plant site. Federal regulations require this
secondary level of financial protection. The Nuclear Regulatory Commission exempted San Onofre Unit 1 from this
secondary level, effective June 1994. The maximum deferred premium for each nuclear incident is $101 million per
reactor, but not more than $10 million per reactor may be charged in any one year for each incident. Based on
its ownership interests, SCE could be required to pay a maximum of $199 million per nuclear incident. However,
it would have to pay no more than $20 million per incident in any one year. Such amounts include a 5% surcharge
if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation.
If the public liability limit above is insufficient, federal regulations may impose further revenue-raising
measures to pay claims, including a possible additional assessment on all licensed reactor operators. The U.S.
Congress has extended the expiration date of the applicable law until December 31, 2004.
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
Page 15
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 began moving
the Unit 1 spent fuel to the dry cask interim spent fuel storage facility at San Onofre during the third quarter
of 2003. By late 2004, the spent fuel pool storage capacity for Units 2 and 3 will then accommodate needs until
2007 for Unit 2 and 2008 for Unit 3. SCE expects to begin using an interim spent fuel storage facility for Units
2 and 3 spent fuel by early 2006.
In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed a
dry cask storage facility. APS plans to continually load casks on a schedule to maintain full core off-load
capability for all three units.
Note 5. Discontinued Operations
On July 10, 2003, the CPUC approved SCE's sale of certain oil storage and pipeline facilities to Pacific
Terminals LLC for $158 million. In third quarter 2003, SCE recorded a $44 million after-tax gain to
shareholders. In accordance with an accounting standard related to the impairment and disposal of long-lived
assets, this oil storage and pipeline facilities unit's results have been accounted for as a discontinued
operation in the financial statements for both the three and nine months ended September 30, 2003. Due to
immateriality, the results of this unit for prior periods have not been restated and are reflected as part of
continuing operations.
For the three and nine months ended September 30, 2003, revenue from discontinued operations was $3 million and
$20 million, respectively, and pre-tax income was $73 million and $83 million, respectively. As of December 31,
2002, assets of discontinued operations were $62 million.
Page 16
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 nine-month periods ended September 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 nine-month periods ended September 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," in October 2001, 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 United States Court of Appeals for the Ninth Circuit seeking to overturn the
federal district court judgment that approved the settlement agreement. In September 2002, the Ninth Circuit
issued its opinion affirming the federal district court on all claims, with the exception of challenges founded
upon California state law, which the Ninth Circuit referred to the California Supreme Court. On August 21, 2003,
the California Supreme Court concluded that the settlement agreement did not violate California law in any of the
respects raised by the Ninth Circuit. On September 8, 2003, TURN filed a petition for rehearing of the
California Supreme Court's decision. On October 22, 2003, the California Supreme Court denied TURN's petition.
The matter will now return to the Ninth Circuit for final disposition, subject to any efforts by TURN to pursue
further federal appeals.
As discussed in "Regulatory Matters--PROACT Regulatory Asset," "--Energy Resource Recovery Account Proceedings,"
"--Generation Procurement Proceedings" and "--Customer Rate-Reduction Plan," SCE fully recovered the
procurement-related obligations account (PROACT) balance during July 2003. On October 14, 2003, the Energy
Division of the CPUC completed its review of PROACT, approved the accounting and rate-making issues related to
PROACT, and eliminated the account effective August 14, 2003. 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 rates by 8% for residential customers, 18% for small
businesses, 13% for medium businesses and 19% for large businesses.
Page 17
RESULTS OF OPERATIONS
Earnings
SCE earnings from continuing operations for the three- and nine-month periods ended September 30, 2003, were $329
million and $650 million, respectively, compared with $234 million and $1.1 billion for the same periods in
2002. Excluding the $480 million adjustment related to SCE's utility retained generation (URG) decision from the
CPUC in second quarter 2002, SCE's year-to-date ended September 30, 2002 earnings were $595 million. SCE's
earnings from continuing operations for the three-month period ended September 30, 2003 increased $95 million
over the same period in 2002, which reflects the favorable resolution of certain regulatory cases recorded in the
three-month period ended September 30, 2003. The regulatory cases include the CPUC's decision on the allocation
of certain overhead costs between rates authorized by the CPUC and rates authorized by the Federal Energy
Regulatory Commission (FERC), the final disposition of the PROACT following the CPUC's review (both of which are
discussed in "--Operating Expenses"), and the Palo Verde Nuclear Generating Station (Palo Verde) incentive awards
(discussed in "--Other Income and Deductions"). These favorable results were partially offset by
performance-based ratemaking (PBR) rewards received in 2002, higher net interest expense and depreciation
expense.
Excluding the $480 million gain in 2002 to implement the URG decision, SCE's earnings from continuing operations
for the nine-month period ended September 30, 2003, increased by $55 million compared to the same period last
year. This increase primarily reflects the favorable resolution of certain regulatory cases at SCE recorded in
the three-month period ended September 30, 2003, as discussed above. Earnings were also affected by higher
operations and maintenance expenses and depreciation expenses, partially offset by higher revenue.
Operating Revenue
SCE's retail sales represented approximately 93% of operating revenue for both the three- and nine-month periods
ended September 30, 2003, and approximately 96% of operating revenue for both the same periods in 2002. Retail
rates are regulated by the CPUC and wholesale rates are regulated by the 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 nine-month periods ended September 30, 2003, compared to the same
periods in 2002, primarily due to increased retail and wholesale revenue. Retail revenue increased in the three-
and nine-month periods mainly due to the recognition of revenue from the 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), an increase in
volume primarily due to warmer weather in 2003, compared to 2002, 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 the California Department of Water Resources (CDWR) for its costs associated with
direct access customers (see discussion below). The increases were partially offset by a decrease in revenue due
to the implementation of a CPUC-approved customer rate-reduction plan effective August 1, 2003, and an increase
in amounts remitted to CDWR for energy purchases, including an allocation adjustment during the nine-month period
ended September 30, 2003, bond-related charges
Page 18
(beginning November 15, 2002) and direct access exit fees (beginning January 1, 2003). 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 CDWR contracts allocated to SCE, excess energy from SCE sources may exist at certain times and is resold in
the energy markets.
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. As part of the CPUC-approved customer rate-reduction
plan, effective August 1, 2003, direct access customers are no longer given a credit since these customers are no
longer billed for generation. Operating revenue for the period in which the credit was given 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, 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 $541 million and $1.4 billion for the three- and nine-month periods ended September 30, 2003,
respectively, compared to $326 million and $922 million for the three- and nine-month periods ended September 30,
2002, respectively.
Operating Expenses
Fuel expense increased for both the three- and nine-month periods ended September 30, 2003, compared to the same
periods in 2002, primarily due to coal-related costs incurred in 2003. The nine-month period increase was also
due to increased generation at one of SCE's coal facilities, partially offset by lower nuclear fuel expenses.
Purchased-power expense increased for the three- and nine-month periods ended September 30, 2003, compared to the
same periods in 2002, mainly due to higher expenses resulting from SCE's resumption of power procurement on
January 1, 2003. The higher expenses resulted from an increase in the number of bilateral contracts entered into
during 2003 and an increase in imbalance energy purchased in 2003. The nine-month period increase also includes
higher expenses related to power purchased by SCE from qualifying facilities (QFs), mainly due to higher spot
natural gas prices in 2003, as compared to 2002.
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 cogeneration QFs are generally tied to spot natural gas prices. During
2003, spot natural gas prices were higher compared to the same periods in 2002. 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.
Provisions for regulatory adjustment clauses - net decreased during the three-month period ended September 30,
2003 and increased during the nine-month period ended September 30, 2003, compared to the same periods in 2002.
The three-month period decrease was mainly due to lower overcollections used to recover SCE's PROACT balance, the
implementation of the CPUC-authorized customer rate-reduction plan, a net increase in energy procurement costs,
an adjustment to a pension-related regulatory reserve and the favorable resolution of certain regulatory cases
recorded in the third quarter of 2003. The regulatory cases include the CPUC decision on the allocation of
certain overhead costs between rates authorized by the CPUC and the FERC (see "Regulatory Matters--Transmission
Rate Case") and the final disposition of the PROACT following the Energy Division of the CPUC's review (see
"Regulatory Matters--PROACT
Page 19
Regulatory Asset"). The nine-month period increase was 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. The increase was almost entirely offset by a decrease in overcollections used to recover the PROACT
balance, an allocation adjustment for CDWR energy purchases, an adjustment to a pension-related regulatory
reserve and the favorable resolution of certain regulatory cases recorded in the third quarter of 2003 as
discussed above.
Other operating and maintenance expense increased during both the three- and nine-month periods ended September
30, 2003, mainly due to higher health-care costs and higher spending on certain CPUC-authorized programs and
higher transmission access charges.
Depreciation, decommissioning and amortization expense increased during both the three- and nine- month periods
ended September 30, 2003, mainly due to a change in the amortization period for SCE's nuclear facilities recorded
in the third quarter of 2002 based on the implementation of a CPUC decision and 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 nine-month periods ended September 30, 2003,
compared to the same periods in 2002, mainly due to lower interest income on the PROACT balance. The nine-month
period decrease also reflects lower interest income from lower average cash balances, compared to the same period
in 2002.
Other nonoperating income increased for both the three- and nine-month periods ended September 30, 2003, compared
to the same periods in 2002. The three-month increase was mainly due to SCE's recognition of performance
rewards, from 2000, related to the Palo Verde and approved by the CPUC during third quarter 2003. The nine-month
increase also reflects performance rewards, from 2001, related to Palo Verde and approved by the CPUC during the
second quarter of 2003, as well as SCE's accrual of PBR revenue, for 2002, under the PBR sharing mechanism filed
with the CPUC during first quarter 2003.
Interest expense - net of amounts capitalized decreased during both the three- and six-month periods ended
September 30, 2003, compared to the same periods in 2002, mainly due to lower interest expense resulting from
lower debt balances (both short- and long-term), as well as lower interest rates. Effective July 1, 2003,
dividend payments on preferred securities subject to mandatory redemption are included as interest expense based
on the adoption of a new accounting standard. The new standard did not allow for prior period restatements,
therefore dividends on preferred securities subject to mandatory redemption for the first six months of 2003 are
not included in interest expense - net of amounts capitalized in the consolidated statements of income. In
addition, the nine-month period decrease reflects lower interest expense in 2003 at SCE due to the accrual of
interest in 2002 related to the 2001 and early 2002 suspension of payments for purchased power. These suspended
payments were paid in March 2002.
Other nonoperating deductions increased during the three- and nine-month periods ended September 30, 2003,
compared to the same periods in 2002, primarily due to lower accruals for regulatory matters at SCE in 2002.
Income Taxes
Income taxes increased for the three-month period ended September 30, 2003 and decreased for the nine-month
period ended September 30, 2003, compared to the same periods in 2002. The three-month increase was primarily
due to an increase in pre-tax income. The nine-month decrease was primarily due to a decrease in pre-tax income,
partially offset by a reduction in SCE's tax expense in 2002 related to
Page 20
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 38% realized in both the three- and nine-month periods, was primarily due to property
related flow-through taxes. In addition, the nine-month period reflects a decrease in the California corporation
franchise tax regulatory liability.
Earnings from Discontinued Operations
SCE's discontinued operations for the three- and nine-month periods ended September 30, 2003 reflect a $44
million (after-tax) gain on the sale of SCE's fuel oil pipeline and storage business.
FINANCIAL CONDITION
Cash Flows from Operating Activities
Net cash provided by operating activities:
In millions Nine Months Ended September 30, 2003 2002
----------------------------------------------------------------------------------------------------------
Continuing operations $ 2,321 $ 291
Discontinued operations (34) --
----------------------------------------------------------------------------------------------------------
$ 2,287 $ 291
----------------------------------------------------------------------------------------------------------
The change in cash provided by operating activities from continuing operations was mainly due to SCE's March 2002
repayment of past-due obligations. The change was also due to timing of cash receipts and disbursements related
to working capital.
Cash Flows from Financing Activities
Net cash used by financing activities was $931 million for the nine-month period ended September 30, 2003, and
$1.7 billion for the comparable period in 2002.
During the nine-month period ended September 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% bonds.
During the nine-month period ended September 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 secured credit facility and made a payment of
$50 million to retire the remainder of the $1.65 billion credit facility.
Page 21
Cash Flows from Investing Activities
Net cash used by investing activities:
In millions Nine Months Ended September 30, 2003 2002
----------------------------------------------------------------------------------------------------------
Continuing operations $ (825) $ (676)
Discontinued operations 147 --
----------------------------------------------------------------------------------------------------------
$ (678) $ (676)
----------------------------------------------------------------------------------------------------------
Cash flows from investing activities from continuing operations 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 nine-month period ended September 30, 2003, were approximately $820 million,
primarily for transmission and distribution assets. Additions to SCE's property and plant for the nine-month
period ended September 30, 2002, were approximately $694 million, primarily for transmission and distribution
assets.
Cash flows provided from investing activities from discontinued operations in 2003 represent net proceeds from
the sale of SCE's fuel oil pipeline and storage business.
Liquidity Issues
SCE expects to meet its continuing obligations from cash and equivalents on hand and operating cash flows.
SCE entered into a litigation settlement agreement with the CPUC in October 2001. The settlement agreement
allowed SCE to recover $3.6 billion of past procurement-related costs through a regulatory balancing account
known as the PROACT, but also prohibited SCE from paying any dividends to its parent, Edison International,
during the period that the costs were being recovered. The recovery of the past procurement-related costs was
completed by July 31, 2003. On October 14, 2003, the CPUC completed its final review of PROACT accounting and
eliminated the PROACT account effective August 14, 2003. Also, 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 September 30, 2003, SCE had $1.7 billion in cash and equivalents and its common equity to total
capitalization ratio, for rate-making purposes, was approximately 54%. The CPUC-authorized level is 48%.
Therefore, on October 16, 2003, SCE transferred through a dividend to Edison International $945 million of equity
that exceeded the CPUC-authorized level. The purpose of the transfer was to begin to rebalance SCE's capital
structure in accordance with CPUC requirements. Following the transfer, the ratio, as of October 31, 2003, was
approximately 49%.
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
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proceeds from the issuance of capital stock or certain 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 debt maturity in 2003 is
$34 million of the 8.95% variable rate notes due November 2003 that were not exchanged. In addition,
approximately $70 million of rate reduction notes are due in the fourth quarter of 2003 (a total of $247 million
is due in the twelve-month period ended September 30, 2004). These notes have a separate cost recovery mechanism
approved by state legislation and CPUC decisions. In addition, $125 million of 5.875% bonds are due in September
2004.
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 September 30, 2003, had approximately $198 million posted as collateral to secure its obligations under
power purchase contracts and to transact through the Independent System Operator (ISO) for imbalance energy.
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
The following is an update to SCE's estimated commitments. See the "Commitments" section in the year-ended 2002
MD&A for a more detailed discussion of commitments.
SCE's long-term debt maturities and sinking-fund requirements for the five twelve-month periods following
September 30, 2003 are: 2004-- $406 million; 2005-- $1.1 billion; 2006-- $447 million; 2007-- $1.2 billion; and
2008-- $68 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 September 30, 2003 are: 2004
--$69 million; 2005-- $69 million; 2006-- $69 million; 2007-- $70 million; and 2008-- $17 million.
MARKET RISK EXPOSURES
SCE's primary market risks include interest rate, generating fuel commodity price and volume and counterparty
credit.
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.
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Commodity Price and Volume Risk
SCE recovers its reasonable power procurement costs through regulatory mechanisms established by the CPUC.
Assembly Bill (AB) 57 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 5% of the total energy needed to serve SCE's
customers, with most of the short position occurring during off-peak hours and on weekends. During 2004, SCE's
expects its residual net short to decline and its residual net long position to increase. SCE's growing residual
net long position arises from an expected increase in deliveries under CDWR contracts allocated to SCE's
customers. In its 2004 procurement plan, currently 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 would not affect SCE's earnings. Factors
that could cause SCE's 2003 and 2004 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 in 2003 and 2004.
Pursuant to CPUC decisions, SCE, as CDWR's limited agent, 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 under CPUC state-mandated contracts. Contract energy prices for most non-renewable
QFs are 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. In October 2003, the CPUC issued a decision
that granted SCE interim authorization to hedge its first and second quarter 2004 natural gas price risks for its
existing QF contracts. Authority for any hedging beyond second quarter 2004, is being considered with SCE's
short-term resource plan described in "Regulatory Matters--Generation Procurement Proceedings."
Credit Risks
Credit risk arises primarily due to the chance that a counterparty under various purchase and sale contracts will
not perform as agreed 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
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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 follows the
credit limits established in its CPUC-approved procurement plan, and, as such, believes that any losses which may
occur, despite prudent credit management practices, should be fully recoverable from ratepayers.
REGULATORY MATTERS
This section presents updates to SCE's regulatory matters using three main subsections: generation and power
procurement, transmission and distribution, and other regulatory matters.
Generation and Power Procurement
CPUC Litigation Settlement Agreement
In October 2001, SCE and the CPUC entered into a settlement of SCE's lawsuit against the CPUC, which sought a
ruling that SCE is entitled to full recovery of its past procurement-related costs incurred during the energy
crisis in accordance with the tariffs filed with the FERC. 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 and other parties appealed to the United States Court of Appeals for the Ninth
Circuit seeking to overturn the stipulated judgment of the federal district court that approved the settlement
agreement. On September 23, 2002, the Ninth Circuit issued its opinion affirming the federal district court on
all claims, with the exception of the challenges founded upon California state law, which the Ninth Circuit
referred to the California Supreme Court.
On August 21, 2003, the California Supreme Court issued its decision on the certified questions, concluding that
the settlement agreement did not violate California law in any of the respects raised by the Ninth Circuit.
Specifically, the California Supreme Court concluded that: the commissioners of the CPUC had the authority to
propose the stipulated judgment in light of the provisions of California's restructuring statute, AB 1890; the
procedures employed by the CPUC in entering the stipulated judgment did not violate California's open meeting law
for public agencies; and the stipulated judgment did not violate California's public utilities code by allegedly
altering rates without a public hearing and issuance of findings.
On September 8, 2003, TURN filed a petition for rehearing of the California Supreme Court's decision. On October
22, 2003, the California Supreme Court denied TURN's petition. The matter will now return to the Ninth Circuit
for final disposition, subject to any efforts by TURN to pursue further federal appeals. In the meantime, the
case is stayed in the federal appellate court. SCE continues to believe it is probable that recovery of its past
procurement costs through regulatory mechanisms, including the PROACT, ultimately will be validated. However,
SCE cannot predict with certainty the ultimate 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 was authorized by the CPUC to recover in retail
electric rates.
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Under a settlement described in "--Customer Rate-Reduction Plan," on July 15, 2003, SCE filed an advice letter
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. At July 31, 2003,
the PROACT regulatory balancing account was overcollected by $148 million. On October 14, 2003, the Energy
Division of the CPUC completed its review of the PROACT, approved the accounting and rate-making issues related
to the PROACT, and eliminated the account effective August 14, 2003. As a result of the favorable resolution of
these issues, SCE recorded a credit of approximately $84 million to provisions for regulatory adjustment clauses
- net on the consolidated statements of income in the third quarter of 2003 (see "Results of Operations--Operating
Expenses").
Energy Resource Recovery Account Proceedings
In an October 24, 2002 decision, the CPUC established the ERRA as the rate-making mechanism to recover SCE's fuel
costs related to its generating stations, purchased-power costs related to cogeneration and renewable contracts,
existing interutility and bilateral contracts that were entered into prior to January 17, 2001, and new
procurement-related costs that SCE began incurring on January 1, 2003, the date on which the CPUC transferred
back to SCE the responsibility for procuring energy resources for its customers. Under this decision, SCE files
semiannual ERRA applications at the beginning of April and October of each year. SCE submitted its ERRA
applications in April and October 2003. The CPUC has not yet issued a decision on these applications. See
"--Generation Procurement Proceedings" for further information.
CDWR Power Purchases and Revenue Requirement Proceedings
In accordance with an emergency order signed by the Governor of California, CDWR began making emergency power
purchases for SCE's customers on January 17, 2001. Amounts SCE bills to and collects from its 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, California Assembly Bill 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, Pacific Gas and Electric (PG&E)
and San Diego Gas & Electric (SDG&E).
As discussed in the "--CDWR Power Purchases and Revenue Requirement Proceedings" disclosure in the year-ended 2002
MD&A, the CPUC allocated to SCE's customers: $3.5 billion of CDWR's total statewide power procurement revenue
requirement of $9 billion for 2001 and 2002; $331 million of CDWR's 2003 bond charge revenue requirement of $745
million; and approximately $1.9 billion of CDWR's total statewide 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. In September 2003, the CPUC issued a decision
ordering that this amount be returned by CDWR to SCE's customers via a one-time bill credit. The CDWR bill
credit had no impact on SCE's earnings.
In September 2003, CDWR released its revenue requirement determination for 2004 establishing a total power
procurement revenue requirement of $5.39 billion statewide, which includes a power charge of $4.517 billion and a
bond charge of $873 million. On an interim basis, the CPUC will allocate the revenue requirement among SCE, PG&E
and SDG&E using the methodology adopted to allocate CDWR's 2003 revenue requirement. Parties will provide
testimony on the ultimate allocation methodology in December 2003 and the CPUC will convene evidentiary hearings
on the matter in
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January 2004. Any increase or decrease in CDWR's bond and power charges will be directly passed through to SCE's
customers.
In September 2003, CDWR also issued the data necessary to true-up its 2001-2002 revenue requirement allocation.
The true-up is to be based on the methodology adopted by the CPUC in the first quarter of 2002 and would result
in SCE's customers owing an additional $41 million to the CDWR. In the proceeding implementing the true-up, PG&E
recommended that the CPUC adopt an allocation method that would result in SCE's customers owing an additional
$289 million of CDWR's costs, while SCE recommended an allocation method that would result in SCE's customers
being owed $532 million. Alternatively, SCE proposed that the customers of each investor-owned utility pay a
bond charge that is proportionate to the bond proceeds allocated to them. This would result in a $50 million to
$60 million per year decrease in the bond charge revenue requirement allocated to SCE's customers over the
20-year life of CDWR's bonds. SCE customers would, however, still owe the additional $41 million associated with
CDWR's 2001-2002 revenue requirement allocation true-up referenced above. Hearings were held on the matter in
October 2003 and a draft decision is expected in December. Any adjustment resulting from this true-up will be
reflected in SCE's customers' share of CDWR's 2004 revenue requirement and will have no impact on earnings.
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 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 received a
credit for the generation costs SCE saved by not serving them. Operating revenue was 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 decision, the CPUC approved a petition for modification of the
interim decision filed by SCE raising direct access customers' responsibility for SCE's past power procurement
costs to $473 million. 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.
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 four categories of energy crisis
related costs to direct access customers. The first category consists of CDWR's power
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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 all direct access customers were responsible for paying a portion of CDWR's bond
charge to recover the principal and financing costs associated with these bonds, except customers who were
continuously on direct access and never used any CDWR power (less than 1% of SCE's load). The second category
relates to CDWR's power procurement costs for the fourth quarter of 2001 and the year 2002. The CPUC stated that
all direct access customers who took bundled service at any time after February 1, 2001, 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 who took bundled service at
any time after February 1, 2001, 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, 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 customers who
depart investor-owned utility service in favor of taking service from a publicly-owned utility. That decision
states that customers switching to municipal service after February 1, 2001, as well as customers of newly
established municipal utilities, will be responsible for paying CRS fees. The exact amount of the CRS obligation
to be paid by customers of these publicly owned utilities is to be determined in a future phase of the proceeding
and has not yet been scheduled. The CPUC affirmed the decision, with modifications, on rehearing and will
consider whether some portion of the "load" served by newly established publicly owned utilities should be exempt
from CRS. Several parties have filed petitions with the California Supreme Court challenging the decision; SCE
filed its response opposing the petitions. 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 its 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 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:
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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 also filed a petition with the
California Supreme Court raising similar arguments. On October 22, 2003, the California Supreme Court denied
both SCE's and TURN's petition.
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 the higher 2003 CDWR revenue requirement allocated to its customers and its own
higher procurement costs. 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.
Hedging Cost Recovery Proceedings
Pursuant to authority granted in SCE's 2001 litigation settlement agreement with the CPUC, 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. On October 16,
2003, the CPUC issued a decision that granted SCE interim authorization to hedge its first and second quarter
2004 natural gas price risks for its existing QF contracts. Authority for any hedging beyond second quarter 2004
is being considered with SCE's short-term resource plan described in "--Generation Procurement Proceedings."
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Generation Procurement Proceedings
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
incurred in compliance with an approved procurement plan.
The CPUC issued an order instituting rulemaking in October 2001 that 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 significant 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. The CPUC also adopted an operating order described below in "--CDWR
Contracts." See the "--Generation Procurement Proceedings" in the year-ended 2002 MD&A for detailed discussion of
these matters. The CPUC 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. 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 will automatically terminate on
December 31, 2003 unless it is approved by that time or the deadline is extended.
In accordance with a ruling by a CPUC administrative law judge (ALJ), 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);
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:
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(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 (see
"--Hedging Cost Recovery Proceedings" for SCE's authority to hedge its natural gas price exposure for the
first six months of 2004);
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 were completed in August 2003. A
decision is expected in December 2003.
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 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 conditions for
contracts to be entered into as part of the RPS process. 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,
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subject to the flexible compliance rules, if and when the utility becomes creditworthy. With respect to standard
contract terms for RPS contracts, the CPUC has requested briefings concerning the terms that should be
standardized. 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. Because
the CPUC failed to act on the application within 60 days of its filing, it is presumed denied and SCE can seek
review of the underlying decision in the California Court of Appeal. SCE is considering whether to seek
appellate review.
On August 29, 2003, SCE initiated a further solicitation for renewable resources with the objective of entering
into additional power purchase agreements to the extent it receives responses which, in its judgment, provide
sufficient ratepayer benefit. On October 3, 2003, SCE received bids in response to the solicitation, which it is
presently evaluating.
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 issued a decision which approved the negotiated operating agreements with CDWR
submitted by PG&E and SDG&E, subject to certain modifications. The decision also required SCE, PG&E and SDG&E to
file gas supply plans for the purchase of natural gas for the CDWR contracts allocated to the respective
utilities by April 17, 2003, and to file subsequent plans every six months thereafter for the term of the
operating order. SCE filed its initial gas supply plan on April 18, 2003, which was approved with minor
modifications by the CPUC on August 26, 2003. SCE filed its second gas supply plan on August 22, 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 the Mohave Generating Station (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 past 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.
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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 October 29, 2003. The Navajo Nation and Hopi Tribe and the coal mining company,
Peabody Western Coal Company, have taken 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. Negotiations have
continued among the relevant parties in an effort to resolve the coal and water supply issues, but no resolution
has been reached. On October 8, 2003, the CPUC indicated that when the CPUC is assured that resolution of the
coal and water supply issues is progressing, hearings on the costs and timelines for all alternatives would be
scheduled.
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 Nuclear Generating Station (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. 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. SCE's GRC filing also requests an $85
million increase in revenue in 2005. A final decision on Phase 1 issues is expected in the fourth quarter of
2003 or the first quarter of 2004.
On May 22, 2003, the CPUC approved SCE's request to establish a memorandum 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; accordingly the final revenue
requirement approved in the final decision will be effective May 22, 2003. However, amounts to be recorded are
subject to review by the CPUC before recovery will be authorized. The amounts to be tracked in the memorandum
account will be subject to recovery or refund depending on the final outcome of the proceeding.
Phase 2 of the GRC proceeding will address revenue allocation and rate design issues. Hearings on this phase are
scheduled to begin in March 2004. Due to the CPUC's adoption in July 2003 of the customer rate-reduction plan
settlement (see "--Customer Rate-Reduction Plan" below), rate design changes in Phase 2 of the GRC will not be
effective until August 2004 at the earliest.
On July 15, 2003, SCE requested that the CPUC open a third phase (Phase 3) of the GRC to consider SCE's request
to track certain security-related costs ordered by the Nuclear Regulatory Commission in a memorandum account for
future recovery in rates. These required Nuclear Regulatory Commission modifications, together with a change in
SCE's California property tax rate will increase SCE's GRC revenue requirement by $23 million during 2004-2005.
In a separate matter, a change in federal tax law is expected to lower SCE's federal income tax liability for
2004 and 2005 by the same amount. SCE has
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reached agreement with GRC intervenors to fund the security-related increase with the surplus general rate case
revenue requirement resulting from the change in income and property taxes. As a result, on October 23, 2003,
the ALJ in the GRC granted SCE's request to withdraw Phase 3.
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. On August 21, 2003, the CPUC granted
SCE's petition. Thus, SCE's 2003 cost of capital decision, issued on November 7, 2002, will remain in effect
throughout 2004 and SCE's CPUC-authorized return on equity will be maintained at its current 11.6% level through
2004. SCE's CPUC-authorized costs of long-term debt and preferred stock and SCE's authorized rate-making capital
structure are also maintained at their current levels through 2004.
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 4,721 of the
violations alleged by the 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 this decision, assuming that the CPUC would 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. On August
21, 2003, the CPUC issued a decision approving SCE's application. On September 2, 2003, SCE filed an advice
letter with the CPUC to implement recovery of approximately $133 million in accordance with the decision. The
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advice filing was approved on September 29, 2003 and SCE credited this amount to provisions for regulatory
adjustment clauses - net in the consolidated statements of income (see "Results of Operations--Operating
Expenses"). On September 22, 2003, the CPUC's Office of Ratepayer Advocates applied for rehearing of the August
21, 2003 decision. SCE cannot, at this time, predict how or when the CPUC will resolve the rehearing application.
Wholesale Electricity and Gas Markets
In 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 "--Wholesale Electricity Markets" disclosure in the
year-ended 2002 MD&A, the FERC issued orders in March 2003 that initiated procedures for determining additional
refunds arising from market manipulation by energy suppliers. The 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
on 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 a FERC 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
sought rehearing of the March 26, 2003 and April 22, 2003 orders. On October 16, 2003, the FERC issued an order
on SCE's rehearing request, upholding its March 26, 2003 order. On June 25, 2003, the FERC issued two sets of
enforcement orders. The first set ordered 54 entities, including SCE, to show cause concerning gaming or
anomalous market behavior during the period January 1, 2001 to June 20, 2001. SCE has provided information to
the FERC staff demonstrating that it did not engage in gaming or anomalous market behavior, filed its response to
the show cause order on September 2, 2003, and worked with the FERC staff to resolve the issue. On November 3,
2003, the FERC staff filed a motion to dismiss the charges against SCE. The second set of enforcement orders
ordered 25 entities to show cause concerning gaming and anomalous market behavior in concert with Enron and other
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. Since these orders,
the FERC staff has filed numerous motions to dismiss against various respondents in the proceeding and has
entered into settlements with a number of respondents. SCE and other parties subject to the order have filed
dozens of opposition pleadings. 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 actually realized by SCE will be
refunded to ratepayers. On October 30, 2003, the CPUC issued a decision on the accounting and rate-making
mechanisms related to the consideration that will be received by regulated gas and electric utilities under a
settlement with El Paso Natural Gas Company and other parties. Based on this decision, SCE will refund to
ratepayers 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. Refunds from El Paso will not be
received until the proposed settlement is approved by the California Superior Court in San Diego County. A
hearing for approval of the proposed settlement is scheduled for November 20, 2003.
Other Regulatory Matters
Catastrophic Event Memorandum Account
The catastrophic event memorandum account (CEMA) is a CPUC-authorized mechanism that allows SCE to immediately
commence the tracking of all of its incremental costs associated with declared disasters or emergencies and to
subsequently receive rate recovery of its reasonably incurred costs upon CPUC approval. Incremental costs
associated with restoring utility service; repairing, replacing or
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restoring damaged utility facilities; and complying with governmental agency orders are tracked in the CEMA. If
a catastrophic event occurs, SCE is to inform the CPUC within thirty days after such event if SCE has starting
tracking costs in the CEMA. SCE currently has a CEMA for the bark beetle emergency and recently initiated a
second CEMA associated with the fires that occurred in SCE territory in October 2003. Costs tracked through the
CEMA mechanism are expected to be recovered in future rates with no impact on earnings.
Bark Beetle CEMA
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 track its
incremental expenses associated with the bark beetle emergency incurred on or after April 3, 2003, in the CEMA.
The CPUC also authorized SCE to file annual advice letters demonstrating the reasonableness of the recorded costs
and requesting rate recovery of the costs deemed reasonable by the CPUC. On October 10, 2003, the CPUC
authorized SCE to reimburse property owners for their removal of dead or dying trees (on or after April 3, 2003)
that could impact SCE's electrical lines and facilities. SCE estimates that it may incur several hundred million
dollars in incremental expenses over the next several years to remove over 350,000 of these trees. This cost
estimate is subject to significant change, depending on a number of evolving circumstances, including, but not
limited to the spread of the bark beetle infestation, the speed at which trees can be removed, and tree disposal
costs. In addition, although the recent devastating fires in southern California burned in some bark beetle
infested areas, it is too early to determine what impact, if any, the fires may have on the number and location
of dead and dying trees that are to be removed.
Fire-Related CEMA
During the last two weeks of October 2003, wildfires damaged SCE's electrical infrastructure, primarily in the
San Bernardino Mountains of Southern California where an estimated 1,500 power poles and 220 transformers were
damaged or downed. SCE has notified the CPUC that it initiated a CEMA on October 21, 2003 to track the
incremental costs to repair and restore its infrastructure. These costs are preliminarily estimated to be in
excess of $50 million.
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 August 1, 2003. The
decision approved an April 2003 settlement agreement between SCE and active parties in this proceeding in which
rates are reduced by 8% for residential customers, 18% for small businesses, 13% for medium businesses and 19%
for large businesses, and had no impact on SCE's earnings. 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.
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OTHER DEVELOPMENTS
Clean Air Act
A federal district court, ruling on a lawsuit filed by the United States Environmental Protection Agency (EPA),
found on August 7, 2003, that the Ohio Edison Company violated requirements of the New Source Review (NSR)
program within the Clean Air Act by upgrading certain coal-fired power plants without first obtaining the
necessary preconstruction permits. On August 26, 2003, another federal district court, ruling in an NSR
enforcement action against Duke Energy Corporation, adopted a different interpretation of the NSR provisions that
could limit liability for similar upgrade projects.
In addition, however, EPA, on October 27, 2003, issued its final rule (effective December 26, 2003) revising its
regulations to define more clearly a category of activities that are not subject to NSR requirements under the
"routine maintenance, repair and replacement" exclusion. This regulation may mitigate some or all of the
potential impact of the Ohio Edison decision, particularly as to future repair and replacement projects.
Both recent judicial decisions and the newly issued regulation are currently under review by SCE, to assess what
implications, if any, they will have on the operation of domestic power plants owned or operated by SCE, or on
SCE's results of operations or financial position.
Employee Compensation and Benefit Plans
On July 31, 2003, a federal district court held that the formula used in International Business Machine
Corporation's (IBM) cash balance pension plan violated the age discrimination provisions of the Employee
Retirement Income Security Act of 1974. The formula for SCE's cash balance pension plan does not meet the
standard set forth in that federal district court's decision. The IBM decision, however, conflicts with the
decisions from two other federal district courts and with the proposed regulations for cash balance plans issued
by the Internal Revenue Service in December 2002. IBM has announced that it will appeal the decision to the
United States Court of Appeals for the Seventh Circuit. 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 being 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 rate-making process.
San Onofre Steam Generators
Like other nuclear power plants with steam generators made of 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 and SCE's analysis of recent inspection data, SCE has determined that the existing San
Onofre Units 2 and 3 steam generators may not be adequate to permit continued operation beyond the scheduled
refueling outages in 2009-2010. SCE currently estimates that the total project cost of replacing the steam
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generators should not exceed $775 million. If the other plant co-owners agree to pay their proportionate shares
of the costs, SCE's 75% share should not exceed $581 million. SCE currently is reviewing the advisability of
replacing the steam generators, as well as additional issues, including participation by co-owners, regulatory
approvals, and permits. To obtain delivery of replacement steam generators in 2009, SCE expects that it may need
to enter into fabrication commitments in 2004. If SCE elects to proceed with replacing the steam generators, it
would seek the prior approval of the CPUC. If the CPUC finds investment in the steam generators to be reasonable
and cost effective, the investment should be reflected in SCE's retail rates for recovery over the remaining
useful life of the plants.
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. On July 21, 2003,
SCE filed an application with the CPUC proposing a power-purchase agreement between SCE and Mountainview Power
Company LLC. Hearings were completed in October 2003, and a CPUC decision on this matter is expected in December
2003. 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 $44 million after-tax gain to shareholders 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 (ARO) 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 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
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the accumulated provision for depreciation and decommissioning on the consolidated balance sheets in SCE's
Annual Report on Form 10-K for the year ended December 31, 2002.
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
September 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 $2.4 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 $2.0 billion
collected through rates for cost of removal of plant assets not considered to be legal obligations remain in
accumulated depreciation and decommissioning.
Effective July 1, 2003, SCE adopted a new accounting standard, Accounting for Certain Financial Instruments with
Characteristics of both Liabilities and Equity, which required 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. Effective July 1, 2003, SCE reclassified its preferred stock subject to mandatory
redemption to the liability section of its consolidated balance sheet. This item was previously classified
between liabilities and equity. In addition, effective July 1, 2003, dividend payments on this instrument are
now included in interest expense - net of amounts capitalized on the consolidated statements of income. Prior
period financial statements are not permitted to be restated for these changes. Therefore, upon adoption there
was no cumulative impact incurred due to this accounting change.
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;
o changes in prices and availability of wholesale electricity, natural gas, other fuels, transmission
services, and other changes in operating costs, which could affect SCE's operations and financial results;
o the effects on SCE of energy legislation currently pending in the United States Congress and other
legislation that may be adopted in the future;
o the effects of changes in interest rates and investment returns on employee benefit plans and nuclear
decommissioning trusts;
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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 efforts by municipalities and other local government entities to compete with SCE by forming public
power entities in new development areas, acquiring SCE's electric distribution facilities, or providing
electricity to aggregated SCE customers without paying SCE's full stranded costs and CDWR costs;
o power plant operation risks, including equipment failures, availability, output and labor issues;
o the outcome of current and future litigation and other legal proceedings involving SCE;
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.
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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 Financial
Condition and Results of Operations, 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.
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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 year ended December 31, 2002
(2002 Form 10-K), 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) and in Part II, Item 1 of SCE's Quarterly Report on Form 10-Q for the period ending June 30,
2003, 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 "REGULATORY MATTERS - CPUC Litigation Settlement Agreement."
Irvine Underground Storage Tank Matter
In a letter dated October 20, 2003, the office of the District Attorney of Orange County, California alleged that
reports generated by the Orange County Health Care Agency revealed that SCE violated the California Code of
Regulations by failing to upgrade an underground storage tank in Irvine, California, between December 23, 1998
and November 4, 2001. While the tank has been removed, the previous violations are alleged to still exist. The
October 20, 2003 letter advised that it is the intention of the District Attorney's office to bring an action
against SCE in Orange County Superior Court, seeking civil penalties ranging from $500 up to $5,000 per tank per
day of violation, and costs of investigation. A prefiling settlement conference has been scheduled for
November 21, 2003.
Navajo Nation Litigation
As previously reported in the 2002 Form 10-K and in the First Quarter 10-Q, on June 18, 1999, SCE was served with
a complaint filed by the Navajo Nation in the United States District Court for the District of Columbia against
Peabody Holding Company and certain of its affiliates (Peabody), Salt River Project Agricultural Improvement and
Power District and SCE (Salt River Project Agricultural Improvement and Power District was later dismissed as a
defendant). The complaint asserts claims against the defendants for, among other things, violations of the
federal RICO statute, interference with fiduciary duties and contractual relations, fraudulent misrepresentation
by nondisclosure and various contract-related claims.
Some of the issues included in this case were addressed by the United States Supreme Court in a separate legal
proceeding filed by the Navajo Nation against the United States Department of Interior in the Court of Federal
Claims. In that action, the Navajo Nation claimed that the Government breached its fiduciary duty concerning
negotiations relating to the coal lease involved in the Navajo Nation's lawsuit against SCE and Peabody. On
March 4, 2003, the Supreme Court concluded, by majority decision, that there was no breach of a fiduciary duty
and that the Navajo Nation did not have a right to relief against the Government. On April 28, 2003, SCE filed
in the action pending against it and Peabody a motion for summary judgment based on the foregoing conclusion of
the Supreme Court. That motion remains pending.
On October 24, 2003, the Court of Appeals, on remand from the Supreme Court, issued a decision remanding the
action brought by the Navajo Nation against the Government back to the Court of Federal Claims for further
proceedings. The Court of Appeals, acting on a "suggestion on remand" filed by the Navajo Nation, held in its
October 24, 2003 decision that the Supreme Court's March 4, 2003 decision was focused on a particular statute,
the Indian Mineral Leasing Act of 1938 (IMLA), and therefore did not address
Page 42
the question of whether a "network" of other statutes, treaties and regulations imposed judicially enforceable
fiduciary duties on the United States during the time period in question. The Court of Appeals, however, further
recognized the possibility that the Navajo Nation may have waived the right to assert claims based on the
"network" theory and directed that the Court of Federal Claims decide in the first instance whether such a waiver
had occurred. If no waiver is found, then the Court of Federal Claims is directed to determine whether, apart
from the IMLA and two other statutes that the Supreme Court held did not apply to the subject lease, a "network
of other statutes and regulations" imposes an enforceable fiduciary obligation on the Government and, if so,
whether such duties were breached under the relevant facts. SCE is currently analyzing the extent to which the
Court of Appeals' October 24, 2003 decision will have any impact on the Navajo Nation's claims against SCE and
Peabody and SCE's pending summary judgment motion.
Page 43
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. Section 1350
----------------
* Incorporated by reference pursuant to Rule 12b-32.
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
July 10, 2003 July 11, 2003 5 and 7
August 5, 2003 August 5, 2003 7 and 12**
August 21, 2003 August 22, 2003 5 and 7
----------------
** Reports on Form 8-K reporting events under Item 12 thereunder are furnished to, not filed with, the
Securities and Exchange Commission.
Page 44
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
Dated: November 13, 2003
