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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, 2004
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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 5, 2004
---------------------------------------------------------- ---------------------------------------------------
Common Stock, no par value 434,888,104
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Page
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, 2004 and 2003 1
Consolidated Statements of Comprehensive Income -
Three and Nine Months Ended September 30, 2004 and 2003 1
Consolidated Balance Sheets - September 30, 2004
and December 31, 2003 2
Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2004 and 2003 4
Notes to Consolidated Financial Statements 5
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations 24
Item 3. Quantitative and Qualitative Disclosures About Market Risk 48
Item 4. Controls and Procedures 48
Part II. Other Information:
Item 1. Legal Proceedings 49
Item 6. Exhibits 50
Signatures
Page
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 2004 2003 2004 2003
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(Unaudited)
Operating revenue $ 2,655 $ 2,794 $ 6,527 $ 6,994
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Fuel 254 68 550 175
Purchased power 915 1,013 2,022 2,187
Provisions for regulatory adjustment clauses - net (34) 332 (85) 1,141
Other operation and maintenance 603 516 1,752 1,473
Depreciation, decommissioning and amortization 188 215 628 603
Property and other taxes 43 42 134 125
Net gain on sale of utility plant -- (5) -- (5)
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Total operating expenses 1,969 2,181 5,001 5,699
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Operating income 686 613 1,526 1,295
Interest and dividend income 5 17 14 96
Other nonoperating income 5 20 50 49
Interest expense - net of amounts capitalized (101) (108) (310) (346)
Other nonoperating deductions (10) (8) (42) (24)
Minority interest (151) -- (236) --
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Income from continuing operations before tax 434 534 1,002 1,070
Income tax 174 203 398 411
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Income from continuing operations 260 331 604 659
Income from discontinued operations - net of tax -- 44 -- 50
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Net income 260 375 604 709
Dividends on preferred stock
subject to mandatory redemption -- -- -- 5
Dividends on preferred stock
not subject to mandatory redemption 1 1 4 4
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Net income available for common stock $ 259 $ 374 $ 600 $ 700
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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 2004 2003 2004 2003
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(Unaudited)
Net income $ 260 $ 375 $ 604 $ 709
Other comprehensive income, net of tax:
Amortization of cash flow hedges 1 1 3 2
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Comprehensive income $ 261 $ 376 $ 607 $ 711
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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 2004 2003
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(Unaudited)
ASSETS
Cash and equivalents $ 188 $ 95
Restricted cash 70 66
Receivables, less allowances of $32 and $30
for uncollectible accounts at respective dates 954 751
Accrued unbilled revenue 510 408
Fuel inventory 7 10
Materials and supplies, at average cost 192 168
Accumulated deferred income taxes - net 224 563
Prepayments and other current assets 94 58
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Total current assets 2,239 2,119
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Nonutility property - less accumulated provision
for depreciation of $543 and $24 at respective dates 519 116
Property of variable interest entities - net 384 --
Nuclear decommissioning trusts 2,609 2,530
Other investments 181 153
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Total investments and other assets 3,693 2,799
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Utility plant, at original cost:
Transmission and distribution 15,396 14,861
Generation 1,367 1,371
Accumulated provision for depreciation (4,588) (4,386)
Construction work in progress 737 600
Nuclear fuel, at amortized cost 153 141
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Total utility plant 13,065 12,587
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Regulatory assets - net 265 510
Other deferred charges 537 506
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Total deferred charges 802 1,016
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Total assets $ 19,799 $ 18,521
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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 2004 2003
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(Unaudited)
LIABILITIES AND SHAREHOLDERS' EQUITY
Short-term debt $ -- $ 200
Long-term debt due within one year 247 371
Preferred stock to be redeemed within one year 9 9
Accounts payable 1,105 891
Accrued taxes 608 475
Regulatory liabilities - net 9 361
Other current liabilities 1,236 1,308
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Total current liabilities 3,214 3,615
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Long-term debt 5,133 4,121
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Accumulated deferred income taxes - net 2,748 2,726
Accumulated deferred investment tax credits 128 136
Customer advances and other deferred credits 524 429
Power-purchase contracts 154 213
Preferred stock subject to mandatory redemption 139 141
Accumulated provision for pensions and benefits 386 330
Asset retirement obligations 2,153 2,084
Other long-term liabilities 251 242
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Total deferred credits and other liabilities 6,483 6,301
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Total liabilities 14,830 14,037
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Commitments and contingencies (Notes 2 and 4)
Minority interest 477 --
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Common stock (434,888,104 shares outstanding at each date) 2,168 2,168
Additional paid-in capital 347 338
Accumulated other comprehensive loss (16) (19)
Retained earnings 1,864 1,868
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Total common shareholder's equity 4,363 4,355
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Preferred stock not subject to mandatory redemption 129 129
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Total shareholders' equity 4,492 4,484
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Total liabilities and shareholders' equity $ 19,799 $ 18,521
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The accompanying notes are an integral part of these financial statements.
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SOUTHERN CALIFORNIA EDISON COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
Nine Months Ended
September 30,
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In millions 2004 2003
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(Unaudited)
Cash flows from operating activities:
Income from continuing operations $ 604 $ 659
Adjustments to reconcile to net cash provided by operating activities:
Depreciation, decommissioning and amortization 628 603
Other amortization 72 76
Minority interest 236 --
Deferred income taxes and investment tax credits 271 (168)
Regulatory assets - long-term - net 284 414
Energy options (44) 62
Other assets (13) (9)
Other liabilities 39 (292)
Changes in working capital net of effects from
consolidation of variable interest entities:
Receivables and accrued unbilled revenue (252) (170)
Regulatory liabilities - short-term - net (352) 792
Fuel inventory, materials and supplies (9) (5)
Prepayments and other current assets (38) (54)
Accrued interest and taxes 112 228
Accounts payable and other current liabilities 119 185
Operating cash flows from discontinued operations -- (34)
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Net cash provided by operating activities 1,657 2,287
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Cash flows from financing activities:
Long-term debt issued 1,598 (11)
Long-term debt repaid (967) (729)
Bonds remarketed - net 350 --
Redemption of preferred stock (2) (6)
Rate reduction notes repaid (177) (176)
Short-term debt financing - net (200) --
Cash dividends to minority interest (178) --
Dividends paid (599) (9)
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Net cash used by financing activities (175) (931)
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Cash flows from investing activities:
Additions to property and plant (1,125) (820)
Acquisition costs related to nonutility generation plant (285) --
Proceeds from sale of property -- 5
Contributions to nuclear decommissioning trusts - net (62) (16)
Sales of investments in other assets 4 6
Investing cash flows from discontinued operations -- 147
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Net cash used by investing activities (1,468) (678)
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Effect of consolidation of variable interest entities on cash 79 --
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Net increase in cash and equivalents 93 678
Cash and equivalents, beginning of period 95 992
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Cash and equivalents, end of period, continuing operations $ 188 $ 1,670
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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, 2004 are not necessarily indicative of the operating
results for the full year.
The quarterly report should be read in conjunction with Southern California Edison Company's (SCE) Annual Report
on Form 10-K for the year ended December 31, 2003 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 2003 Annual Report. SCE follows the same accounting policies for interim reporting purposes,
with the exception of the change in accounting for variable interest entities (VIEs).
SCE's nonutility property, including construction in progress, is capitalized at cost, including interest accrued
on borrowed funds that finance construction.
Effective March 31, 2004, SCE began consolidating four cogeneration projects for which SCE typically purchases
100% of the energy produced under long-term power-purchase agreements, in accordance with a new accounting
standard for the consolidation of variable interest entities (see below).
Certain prior-period amounts were reclassified to conform to the September 30, 2004 financial statement
presentation.
Dividend Restriction
The California Public Utilities Commission (CPUC) regulates SCE's capital structure, limiting the dividends it
may pay Edison International. In SCE's most recent cost of capital proceeding, the CPUC set an authorized
capital structure for SCE which included a common equity component of 48%. SCE determines compliance with this
capital structure based on a 13-month weighted-average calculation. At September 30, 2004, SCE's 13-month
weighted-average common equity component of total capitalization was 51%. At September 30, 2004, SCE had the
capacity to pay $230 million in additional dividends based on the 13-month weighted-average method. Based on
recorded September 30, 2004 balances, SCE's common equity to total capitalization ratio, for ratemaking purposes,
was 50%. SCE had the capacity to pay $139 million of additional dividends to Edison International based on
September 30, 2004 recorded balances.
New Accounting Principles
In December 2003, the Financial Accounting Standards Board issued a revision to an accounting Interpretation
(originally issued in January 2003), Consolidation of Variable Interest Entities. The primary objective of the
Interpretation is to provide guidance on the identification of, and financial reporting for, VIEs, where control
may be achieved through means other than voting rights. Under the
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Interpretation, the enterprise that is expected to absorb or receive the majority of a VIE's expected losses or
residual returns, or both, must consolidate the VIE unless specific exceptions apply. This Interpretation is
effective for special purpose entities, as defined by accounting principles generally accepted in the United
States, as of December 31, 2003, and all other entities as of March 31, 2004.
SCE has 272 long-term power-purchase contracts with independent power producers that own qualifying facilities
(QFs). SCE was required under federal law to sign such contracts, which typically require SCE to purchase 100%
of the power produced by these facilities under terms and pricing controlled by the CPUC. SCE conducted a review
of its QF contracts and determined that SCE has variable interests in 17 contracts with gas-fired cogeneration
plants that are potential variable interest entities and that contain variable pricing provisions based on the
price of natural gas and for which SCE does not have sufficient information to determine if the projects qualify
for a scope exception. SCE requested from the entities that hold these contracts the financial information
necessary to determine whether SCE must consolidate these projects. All 17 entities declined to provide SCE with
the necessary financial information. However, four of the 17 contracts are with entities 49%-50% owned by a
related party, Edison Mission Energy (EME). EME is an indirect wholly owned subsidiary of SCE's parent company,
Edison International. Although the four related-party entities have declined to provide their financial
information to SCE, Edison International has access to such information and has provided combined financial
statements to SCE. SCE has determined that it must consolidate the four power projects partially owned by EME
based on a qualitative analysis of the facts and circumstances of the entities, including the related-party
nature of the transaction. SCE will continue to attempt to obtain information for the other 13 projects in order
to determine whether they should be consolidated by SCE.
The remaining 255 contracts will not be consolidated by SCE under the new accounting standard, since SCE lacks a
variable interest in these contracts or the contracts are with governmental agencies, which are generally
excluded from the standard.
SCE analyzes its potential variable interests by calculating operating cash flows. A fixed-price contract to
purchase electricity from a power plant does not transfer sufficient risk to SCE to be considered a variable
interest. A contract with a non-natural-gas-fired plant that is based on the price of natural gas is also not a
variable interest. SCE has other power contracts with non-QF generators. SCE has determined that these
contracts are not significant variable interests.
See "Variable Interest Entities" for further information.
Nuclear
Effective January 1, 2004, San Onofre Nuclear Generating Station (San Onofre) Units 2 and 3 returned to
traditional cost-of-service ratemaking. The July 8, 2004 CPUC decision on SCE's 2003 general rate case returned
Palo Verde Nuclear Generating Station (Palo Verde) to traditional cost-of-service ratemaking retroactive to May
22, 2003 (the date a final CPUC decision was originally scheduled to be issued).
SCE's nuclear plant investments are recorded as a regulatory asset on its balance sheets. This classification
does not affect the rate-making treatment for these assets. SCE had been recovering its investments in San
Onofre and Palo Verde on an accelerated basis, as authorized by the CPUC. The accelerated recovery was to
continue through December 2001, earning a 7.35% fixed rate of return on investment. San Onofre's operating
costs, including nuclear fuel and nuclear fuel financing costs, and incremental capital expenditures, were
recovered through an incentive pricing plan that allowed SCE to
Page 6
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
receive about 4(cent)per kilowatt-hour (kWh) through 2003. Any differences between these costs and the incentive
price flowed through to shareholders. Palo Verde's accelerated plant recovery, as well as operating costs,
including nuclear fuel and nuclear fuel financing costs, and incremental capital expenditures, were subject to
balancing account treatment through the effective date of the 2003 general rate case.
The nuclear rate-making plans were to continue for rate-making purposes at least through the 2003 general rate
case effective date for Palo Verde operating costs and through 2003 for the San Onofre incentive pricing plan.
However, due to the various unresolved regulatory and legislative issues as of December 31, 2000, SCE was no
longer able to conclude that the unamortized nuclear investment was probable of recovery through the rate-making
process. As a result, this balance was written off as a charge to earnings at that time. As a result of the
CPUC's April 4, 2002 decision that returned SCE's utility-retained generation assets to cost-based ratemaking, SCE
reestablished for financial reporting purposes its unamortized nuclear investment and related flow-through taxes,
retroactive to August 31, 2001, based on a 10-year recovery period, effective January 1, 2001, with a
corresponding credit to earnings. SCE adjusted the procurement-related obligations account (PROACT) regulatory
asset balance to reflect recovery of the nuclear investment in accordance with the final utility-retained
generation decision.
In a September 2001 decision, the CPUC granted SCE's request to continue the rate-making treatment for Palo
Verde, including the continuation of the nuclear unit incentive procedure with a 5(cent)per kWh cap on replacement
power costs, until resolution of SCE's 2003 general rate case or further CPUC action. Palo Verde's nuclear unit
incentive procedure calculated a reward for performance of any unit above an 80% capacity factor for a fuel
cycle. The San Onofre Units 2 and 3 incentive rate-making plan continued until December 31, 2003.
Page 7
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 2004 2003
----------------------------------------------------------------------------------------------------------
(Unaudited)
Current:
Regulatory balancing accounts and other - net $ (9) $ (361)
----------------------------------------------------------------------------------------------------------
Long-term:
Flow-through taxes - net 1,056 974
Rate reduction notes - transition cost deferral 769 949
Unamortized nuclear investment - net 618 601
Nuclear-related ARO investment - net 276 288
Unamortized coal plant investment - net 65 66
Unamortized loss on reacquired debt 246 222
Environmental remediation 61 71
Asset retirement obligation (ARO) (716) (720)
Costs of removal (2,102) (2,020)
Regulatory balancing accounts and other - net (8) 79
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265 510
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Total $ 256 $ 149
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The regulatory asset related to the rate reduction notes will be recovered over the terms of those notes. The
net regulatory asset related to the unamortized nuclear investment will be recovered by the end of the remaining
useful lives of the nuclear assets. SCE has requested a four-year recovery period for the net regulatory asset
related to its unamortized coal plant investment. CPUC approval is pending. The other regulatory assets and
liabilities are being recovered through other components of electric rates.
Balancing account undercollections and overcollections accrue interest based on a three-month commercial paper
rate published by the Federal Reserve. Income tax effects on all balancing account changes are deferred.
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 its 2003 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 8
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 2004 2003 2004 2003
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income available for common stock, as reported $ 259 $ 374 $ 600 $ 700
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 2 1 6 3
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 2 2 6 4
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Pro forma net income available for common stock $ 259 $ 373 $ 600 $ 699
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Supplemental Cash Flows Information
Nine Months Ended
September 30,
------------------------------------------------------------------------------------------------------------
In millions 2004 2003
------------------------------------------------------------------------------------------------------------
(Unaudited)
Non-cash investing and financing activities:
Details of consolidation of variable interest entities:
Assets $ 458 --
Liabilities (537) --
Reoffering of pollution-control bonds $ 196 --
Details of pollution-control bond redemption:
Release of funds held in trust $ 20 --
Pollution-control bonds redeemed (20) --
Details of long-term debt exchange offer:
Variable rate notes redeemed $ -- $ (966)
First and refunding bonds issued -- 966
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Variable Interest Entities
SCE has variable interests in contracts with certain qualifying facilities that contain variable contract pricing
provisions based on the price of natural gas. Further, four of these contracts are with entities that are
partnerships owned in part by a related party, EME. These four contracts have 20-year terms. The qualifying
facilities sell electricity to SCE and steam to non-related parties. Under a new accounting standard, SCE has
consolidated these four projects effective March 31, 2004. Prior periods have not been restated. The book value
of the projects' plant assets at September 30, 2004 is $384 million ($896 million at original cost less $512
million in accumulated depreciation).
Page 9
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Project Capacity Termination Date EME Ownership
------- -------- --------------- -------------
Kern River 290 MW August 2005 50%
Midway-Sunset 200 MW May 2009 50%
Sycamore 300 MW December 2007 50%
Watson 340 MW December 2007 49%
SCE has no investment in, nor obligation to provide support to, these entities other than its requirement to make
contract payments. Any profit or loss generated by these entities will not effect SCE's income statement, except
that SCE would be required to recognize losses if these projects have negative equity in the future. These
losses, if any, would not affect SCE's liquidity. Any liabilities of these projects are non-recourse to SCE.
SCE has no controlling ownership interest in the four entities that have been consolidated under the new
accounting Interpretation and has no legal or contractual rights to compel these entities to provide information
to SCE. As a result, SCE has no legal, contractual or other right to design, establish, maintain or evaluate the
effectiveness of internal controls over financial reporting for these consolidated variable interest entities.
As a result, SCE will not include these variable interest entities in its year-end conclusion regarding internal
controls over financial reporting.
The variable interest entities' operating costs, instead of purchased power expense, are shown in SCE's income
statements effective April 1, 2004. Further, SCE's operating revenue now includes revenue from the sale of steam
by these four projects. The table below shows the effect on SCE's consolidated statements of income now that
these variable interest entities are consolidated.
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------------------------------------------------------------------------------------
In millions 2004 2003
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Operating revenue $ 96 $ 190
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Fuel 187 375
Purchased power (270) (478)
Other operation and maintenance 19 39
Depreciation, decommissioning and amortization 9 18
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Total operating expenses (55) (46)
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Operating income 151 236
Minority interest (151) (236)
-------------------------------------------------------------------------------------------------------------------
Income from continuing operations before tax $ -- $ --
-------------------------------------------------------------------------------------------------------------------
As noted under New Accounting Principles, SCE also has 13 other contracts with certain qualifying facilities that
contain variable pricing provisions based on the price of natural gas and are considered to be variable interest
entities. SCE might be considered to be the consolidating entity under the new accounting standard. However,
these entities are not legally obligated to provide the financial information to SCE that is necessary to
determine whether SCE must consolidate these entities. These 13 entities have declined to provide SCE with the
necessary financial information. SCE will continue to attempt to obtain information for these projects in order
to determine whether they should be consolidated by SCE. The aggregate capacity dedicated to SCE for these
projects is 359 MW. SCE paid
Page 10
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$77 million and $173 million, respectively, for the three and nine months ended September 30, 2004 and
$73 million and $164 million, respectively, for the three and nine months ended September 30, 2003 to these
projects. These amounts are recoverable in utility customer rates. SCE has no exposure to loss as a result of
its involvement with these projects. In third quarter 2004, SCE received additional information about the legal
structure of five projects previously classified as potential variable interest entities subject to consolidation
and determined that those projects are not variable interest entities.
Note 2. Regulatory Matters
Further information on regulatory matters, including proceedings for California Department of Water Resources
(CDWR) power purchases and revenue requirements, and generation procurement, is described in Note 2 of "Notes to
Consolidated Financial Statements" included in SCE's 2003 Annual Report.
CPUC Litigation Settlement Agreement
As discussed in the "CPUC Litigation Settlement Agreement" disclosure in Note 2 of "Notes to Consolidated
Financial Statements" included in SCE's 2003 Annual Report, in October 2001, SCE and the CPUC entered into a
settlement of SCE's lawsuit against the CPUC that allowed SCE to recover $3.6 billion in past procurement-related
obligations. The Utility Reform Network, 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 2001 CPUC settlement agreement. In September 2002, the Ninth Circuit Court 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 Court referred to the California Supreme Court.
In August 2003, the California Supreme Court concluded that the 2001 CPUC settlement agreement did not violate
California law in any of the respects raised by the Ninth Circuit Court. The matter was returned to the Ninth
Circuit Court for final disposition and in December 2003, the Ninth Circuit Court unanimously affirmed the
original stipulated judgment of the federal district court. In January 2004, the Ninth Circuit Court issued its
mandate, relinquishing jurisdiction of the case and returning jurisdiction to the federal district court. No
petitions were filed within the 90-day period in which parties could seek discretionary review by the United
States Supreme Court of the federal district court's decision. Accordingly, the appeals of the stipulated
judgment approving the 2001 CPUC settlement agreement have been resolved in SCE's favor.
Electric Line Maintenance Practices Proceeding
In August 2001, the CPUC issued an order instituting investigation 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, which alleged a pattern of noncompliance with the CPUC's general orders for the maintenance
of electric lines for 1998-2000.
In an April 22, 2004, decision, the CPUC imposed minor penalties ($656,000) related to SCE's overhead and
underground electric line maintenance practices for failing to make repairs within a reasonable amount of time.
The decision provides SCE with more flexibility in scheduling inspections, but requires SCE to meet and confer
with the CPUC staff on several issues, including revisions to its maintenance priority system and possible
alternatives to the existing high voltage signage requirements.
Page 11
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
General Rate Case (GRC)
On May 3, 2002, SCE filed an application for its 2003 GRC, requesting an increase of $286 million in SCE's base
rate revenue requirement, which was subsequently revised to an increase of $251 million. The application also
proposed an estimated base rate revenue decrease of $78 million in 2004, and a subsequent increase of
$116 million in 2005. The forecast reduction in 2004 was largely attributable to the expiration of the San Onofre
incremental cost incentive pricing (ICIP) rate-making mechanism at year-end 2003 and a forecast of increased
sales.
The CPUC issued a final decision on July 8, 2004, authorizing an annual increase of approximately $73 million in
base rates, retroactive to May 22, 2003 (the date a final CPUC decision was originally scheduled to be issued).
The decision also authorized a base rate revenue decrease of $49 million in 2004, and a subsequent increase of
$84 million in 2005. During the second quarter of 2004, SCE recorded pre-tax net regulatory adjustments of
$180 million as a result of the implementation of the 2003 GRC decision, primarily relating to the recognition of
revenue from the rate recovery of pension contributions during the time period that the pension plan was fully
funded, the resolution of the allocation of costs between transmission and distribution for 1998 through 2000,
partially offset by the deferral of revenue previously collected during the ICIP mechanism for dry cask storage.
The adjustments were included in provisions for regulatory adjustment clauses - net on the income statement.
Because processing of the GRC took longer than initially scheduled, in May 2003, the CPUC approved SCE's request
to establish a memorandum account to track the revenue requirement increase during the period between May 22,
2003 and the date a final decision was adopted. In July 2004, SCE submitted an advice filing to record the
amount in this memorandum account and recorded an approximate $55 million pre-tax gain in the third quarter of
2004 included in operating revenue on the income statement. In addition, during the third quarter of 2004 SCE
recorded approximately $48 million in pre-tax gains related to the 1997-1998 generation-related capital additions
($31 million, which is included in provisions for regulatory adjustment clauses - net on the income statement)
and the related rate recovery ($17 million, which is included in operating revenue on the income statement).
The amount recorded in the GRC memorandum account will be recovered in rates together with the 2004 revenue
requirement authorized by the CPUC in the GRC decision. The GRC rate increase was combined with other rate
changes from pending rate proceedings and became effective August 5, 2004.
Holding Company Proceeding
In April 2001, the CPUC issued an order instituting investigation that reopened the past CPUC decisions
authorizing utilities to form holding companies and initiated an investigation into, among other things:
(1) whether the holding companies violated CPUC requirements to give first priority to the capital needs of their
respective utility subsidiaries; (2) any additional suspected violations of laws or CPUC rules and decisions; and
(3) whether additional rules, conditions, or other changes to the holding company decisions are necessary.
In January 2002, the CPUC issued an interim decision interpreting the CPUC requirement that the holding companies
give first priority to the capital needs of their respective utility subsidiaries. The decision stated that, at
least under certain circumstances, holding companies are required to infuse all types of capital into their
respective utility subsidiaries when necessary to fulfill the utility's obligation to serve its customers. The
decision did not determine whether any of the utility holding companies had violated this requirement, reserving
such a determination for a later phase of the proceedings. In
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February 2002, SCE and Edison International filed an application before the CPUC for rehearing of the decision.
In July 2002, the CPUC affirmed its earlier decision on the first priority requirement 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. In August 2002, Edison International and SCE jointly filed a petition in
California state court requesting a review of the CPUC's decisions with regard to first priority requirements,
and Edison International filed a petition for a review of the CPUC decision asserting jurisdiction over holding
companies. Pacific Gas and Electric (PG&E) and San Diego Gas & Electric Co. (SDG&E) and their respective holding
companies filed similar challenges, and all cases were transferred to the First District Court of Appeal in San
Francisco.
On May 21, 2004, the Court of Appeal issued its decision in the two consolidated cases, and denied the utilities'
and their holding companies' challenges to both CPUC decisions. The Court of Appeal held that the CPUC has
limited jurisdiction to enforce in a CPUC proceeding the conditions agreed to by holding companies incident to
their being granted authority to assume ownership of a CPUC-regulated utility. The Court of Appeal held that the
CPUC's decision interpreting the first priority requirement was not reviewable because the CPUC had not made any
ruling that any holding company had violated the first priority requirement. However, the Court of Appeal
suggested that if the CPUC or any other authority were to rule that a utility or holding company violated the
first priority requirement, the utility or holding company would be permitted to challenge both the finding of
violation and the underlying interpretation of the first priority requirement itself. On June 30, 2004, Edison
International and the other utility holding companies filed with the California Supreme Court a petition for
review of the Court of Appeal decision as to jurisdiction over holding companies, but they and the utilities did
not file a challenge to the decision as to the first priority issue. On September 1, 2004, the California
Supreme Court denied the petition for review. The Court of Appeal's decision on jurisdiction is now final.
The original order instituting investigation into whether the utilities and their holding companies have complied
with CPUC decisions and applicable statutes remains in effect, and the CPUC could initiate further proceedings as
to any of the issues mentioned in the first paragraph above. It is uncertain whether or when the CPUC would do
so.
Mohave Generating Station and Related Proceedings
As discussed in the "Mohave Generating Station and Related Proceedings" disclosure in Note 2 of "Notes to
Consolidated Financial Statements" included in SCE's 2003 Annual Report, in May 2002, SCE filed an application
with the CPUC to address certain issues (mainly coal and slurry-water supply issues) facing the future extended
operation of Mohave Generating Station (Mohave), which is partly owned by SCE. Until the post-2005 coal and
water supply uncertainty is resolved, SCE and other Mohave co-owners cannot determine whether it would be
cost-effective to make the approximately $1.1 billion in Mohave-related investments (SCE's share is
$605 million), including the installation of pollution-control equipment that must be put in place in order for
Mohave to continue to operate beyond 2005, pursuant to a 1999 consent decree concerning air quality.
SCE and other parties submitted further testimony and made various other filings in 2003 in SCE's application
proceeding. Pursuant to the assigned administrative law judge's March 9, 2004 ruling, on April 16, 2004, SCE
updated its position and testimony on cost data and, where data are unavailable, cost estimates for Mohave on the
following options: (1) the cost of permanent shutdown; (2) the cost of installation of required pollution
controls and related capital improvements to allow the facility to continue as a coal-fired plant beyond 2005;
(3) if option 2 is undertaken, the cost of temporary shutdown
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for complete installation of pollution controls, and any costs related to restarting the facility; and (4) other
alternatives and their costs. SCE's testimony presented a summary of work performed to date and provided an
update on the status of the coal and water supply issues. The testimony also stated that SCE does not now have
detailed cost projections for any of the cost categories identified in the March 9, 2004 ruling due to the
uncertainties remaining on these issues. The testimony reiterated SCE's belief that, even if the coal and water
supply issues can be satisfactorily resolved in the near future, thereby avoiding a permanent shutdown, a
temporary shutdown of at least three years is likely.
On October 20, 2004, the CPUC issued a proposed decision which, among other things, (1) directed SCE to continue
negotiations regarding the post-2005 coal and water supply; (2) directed SCE to conduct a study of potential
alternatives to Mohave including solar generation and coal gasification; and (3) provided an opportunity for SCE
to recover in future rates certain Mohave-related costs that SCE has already incurred or is expected to incur by
2006, including certain preliminary engineering costs, water study costs and the costs of the study of Mohave
alternatives. A final decision is not expected before December 2004.
In parallel with the CPUC proceedings, negotiations have continued among the relevant parties in an effort to
resolve the coal and water supply issues. In September 2004 the parties reached agreement on certain "key
principles" related to the study and possible development of a potential alternative water supply, and the
parties agreed to retain a professional mediator for further negotiations, but no further resolution has been
reached.
The outcome of the coal and water negotiations and SCE's application are not expected to impact Mohave's
operation through 2005, but the presence or absence of Mohave as an available resource beyond 2005 could have a
major impact on SCE's long-term resource plan. The outcome of this matter is not expected to have a material
impact on earnings.
For additional matters related to Mohave, see "Navajo Nation Litigation" in Note 4.
Wholesale Electricity and Natural Gas Markets
In 2000, the Federal Energy Regulatory Commission (FERC) initiated an investigation into the justness and
reasonableness of rates charged by sellers of electricity in the California Power Exchange and California
Independent System Operator markets. On March 26, 2003, the FERC staff issued a report concluding that there had
been pervasive gaming and market manipulation of both the electric and natural gas markets in California and on
the West Coast during 2000-2001 and describing many of the techniques and effects of that market manipulation.
SCE is participating in several related proceedings seeking recovery of refunds from sellers of electricity and
natural gas who manipulated the electric and natural gas markets. Under the 2001 CPUC settlement agreement,
mentioned in "CPUC Litigation Settlement Agreement," 90% of any refunds actually realized by SCE will be refunded
to customers, except for the El Paso Natural Gas Company settlement agreement discussed below.
El Paso Natural Gas Company (El Paso) entered into a settlement agreement with parties to a class action lawsuit
(including SCE, PG&E and the State of California) settling claims stated in proceedings at the FERC and in San
Diego County Superior Court that El Paso had manipulated interstate capacity and engaged in other anticompetitive
behavior in the natural gas markets in order to unlawfully raise gas prices at the California border in
2000-2001. The United States District Court has issued an order approving the stipulated judgment and the
settlement agreement has become effective. Pursuant to a
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CPUC decision, SCE will refund to customers amounts received under the terms of the El Paso settlement (net of
legal and consulting costs) through its energy resource recovery account mechanism. In June 2004, SCE received
its first settlement payment of $76 million. Approximately $66 million of this amount was credited to
purchased-power expense and will be refunded to SCE's ratepayers through the energy resource recovery account
over the next 12 months and the remaining $10 million was used to offset SCE's legal costs incurred. Additional
settlement payments totaling approximately $134 million are due from El Paso over a 20-year period. Amounts
El Paso refunds to the CDWR will result in reductions in the CDWR's revenue requirement allocated to SCE in
proportion to SCE's share of the CDWR's power charge revenue requirement.
On July 2, 2004, the FERC approved a settlement agreement between SCE, SDG&E and PG&E and The Williams Cos. and
Williams Power Company, providing for approximately $140 million in refunds and other payments to the settling
purchasers and others against some of Williams' power charges in 2000-2001. On August 2, 2004, SCE received its
approximately $37 million share of the refunds and other payments under the Williams settlement.
On April 26, 2004, SCE, PG&E, SDG&E and several California state governmental entities agreed to settlement terms
with West Coast Power, LLC and its owners, Dynegy Inc. and NRG Energy, Inc. (collectively, Dynegy). The
settlement terms provide for refunds and other payments totaling $285 million, with a proposed allocation to SCE
of approximately $40 million. The Dynegy settlement terms were submitted to the FERC for its approval on
June 28, 2004. The FERC is expected to act on the Dynegy settlement before year-end 2004.
On July 12, 2004, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Duke Energy
Corporation and a number of its affiliates. The settlement terms agreed to with the Duke parties provide for
refunds and other payments totaling in excess of $200 million, with a proposed allocation to SCE of approximately
$45 million. The Duke settlement was submitted to the FERC for its approval on October 1, 2004.
The exact manner in which net settlement proceeds under the Duke, Williams and Dynegy settlements will be
refunded to customers is expected to be the subject of a future CPUC determination. Any settlement amounts
received have been deferred, pending a final decision.
Note 3. Pension Plan and Postretirement Benefits Other Than Pensions
Pension Plan
SCE previously disclosed in Note 7 of "Notes to Consolidated Financial Statements" included in SCE's 2003 Annual
Report that it expects to contribute approximately $33 million to its pension plan in 2004. As of September 30,
2004, $6 million in contributions have been made. Additional funding in 2004 may be restricted by tax-deductible
funding limits.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Expense components are:
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 22 $ 20 $ 66 $ 59
Interest cost 41 40 123 121
Expected return on plan assets (58) (47) (173) (140)
Net amortization and deferral 5 9 16 26
-------------------------------------------------------------------------------------------------------------------
Expense under accounting standards 10 22 32 66
Regulatory adjustment - deferred -- (11) -- (33)
-------------------------------------------------------------------------------------------------------------------
Total expense recognized $ 10 $ 11 $ 32 $ 33
-------------------------------------------------------------------------------------------------------------------
Postretirement Benefits Other Than Pensions
SCE previously disclosed in Note 7 of "Notes to Consolidated Financial Statements" included in SCE's 2003 Annual
Report that it expects to contribute approximately $100 million to its postretirement benefits other than
pensions plan in 2004. As of September 30, 2004, $18 million in contributions have been made. Additional
funding in 2004 may be restricted by tax-deductible funding limits. Additionally, contributions will be lower
than expected due to the impact the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (see
below).
In May 2004, the Financial Accounting Standards Board issued accounting guidance related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003. SCE adopted this guidance effective July 1, 2004,
which resulted in a decrease of $81 million to SCE's accumulated benefit obligation. SCE's third quarter 2004
expense decreased approximately $5 million as a result of the subsidy. According to proposed federal
regulations, SCE's retiree health care plans provide prescription drug benefits that are deemed to be actuarially
equivalent to Medicare benefits. Accordingly, SCE recognized the subsidy in the measurement of its accumulated
obligation and recorded an actuarial gain.
Expense components are:
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
-------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 8 $ 10 $ 30 $ 31
Interest cost 29 31 94 92
Expected return on plan assets (27) (23) (82) (67)
Net amortization and deferral (1) 10 15 30
-------------------------------------------------------------------------------------------------------------------
Total expense $ 9 $ 28 $ 57 $ 86
-------------------------------------------------------------------------------------------------------------------
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
course of business. SCE believes the outcome of these other proceedings will not materially affect its results
of operations or liquidity.
Employee Compensation and Benefit Plans
In April 1999, SCE adopted a cash balance feature for its pension plan. On July 31, 2003, a federal district
court held that the formula used in a cash balance pension plan created by International Business Machine
Corporation (IBM) in 1999 violated the age discrimination provisions of the Employee Retirement Income Security
Act of 1974. In its decision, the federal district court set forth a standard for cash balance pension plans.
This decision, however, conflicts with the decisions from two other federal district courts (including a post-IBM
decision issued in June 2004) and with the proposed regulations for cash balance pension plans issued by Internal
Revenue Service in December 2002. On February 12, 2004, the same federal district court ruled that IBM must make
back payments to workers covered under this plan. IBM has indicated that it will appeal both decisions to the
United States Court of Appeals for the Seventh Circuit. On September 15, 2004 and September 29, 2004, IBM
announced settlements of some of the claims, but stated the company would continue to appeal the two claims
related to age discrimination. The settlements also cap the potential damages IBM will face if it loses its
appeal on the age discrimination issues. The formula for SCE's cash balance pension plan does not meet the
standard set forth in the federal district court's July 31, 2003 decision. SCE cannot predict with certainty the
effect of the two IBM decisions on SCE's cash balance pension plan.
Environmental Remediation
SCE is subject to numerous environmental laws and regulations, which require it to incur substantial costs to
operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past
operations on the environment.
SCE records its environmental remediation liabilities when site assessments and/or remedial actions are probable
and a range of reasonably likely cleanup costs can be estimated. SCE reviews its sites and measures the
liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently
available information, including existing technology, presently enacted laws and regulations, experience gained
at similar sites, and the probable level of involvement and financial condition of other potentially responsible
parties. These estimates include costs for site investigations, remediation, operations and maintenance,
monitoring and site closure. Unless there is a probable amount, SCE records the lower end of this reasonably
likely range of costs (classified as other long-term liabilities) at undiscounted amounts.
SCE's recorded estimated minimum liability to remediate its 24 identified sites is $88 million. The ultimate
costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties
inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable
data for identified sites; the varying costs of alternative cleanup methods; developments resulting from
investigatory studies; the possibility of identifying additional sites; and the time periods over which site
remediation is expected to occur. SCE believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $131 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 $30 million of its
recorded liability, through an incentive mechanism (SCE may request to include
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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
$61 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 $13 million to $25 million. Recorded costs for the twelve months
ended September 30, 2004 were $17 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 (exclusive of interest and penalties), 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 these matters will not result in a material impact on its results of operations or financial
position.
In April 2004, Edison International filed California Franchise Tax amended returns for tax years 1997 through
2002 to abate the possible imposition of new California penalty provisions on transactions that may be considered
as listed or substantially similar to listed transactions described in an Internal Revenue Service notice that
was published in 2001. These transactions include a transaction entered into by an SCE subsidiary, which may be
considered substantially similar to a listed transaction described by the Internal Revenue Service as a
contingent liability company. Edison International filed these amended returns under protest retaining its
appeal rights and SCE believes that Edison International will prevail in an outcome that will not have a material
financial impact on SCE.
Investigations Regarding Performance Incentive Rewards
SCE is eligible under its CPUC-approved performance-based ratemaking (PBR) mechanism to earn rewards or penalties
based on its performance in comparison to CPUC-approved standards of (1) customer satisfaction, (2) employee
injury and illness reporting, and (3) system reliability.
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SCE has been conducting investigations into its performance under these PBR mechanisms and has reported to the
CPUC certain findings of misconduct and misreporting as further discussed below. As a result of the reported
events, the CPUC could institute its own proceedings to determine whether and in what amounts to order refunds or
disallowances of past and potential PBR rewards for customer satisfaction, injury and illness reporting, and
system reliability portions of PBR. The CPUC also may consider whether to impose additional penalties on SCE.
SCE cannot predict with certainty the outcome of these matters or estimate the potential amount of refunds,
disallowances and penalties that may be required.
Customer Satisfaction
SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service
planning group of SCE's transmission and distribution business unit altered or omitted data in attempts to
influence the outcome of customer satisfaction surveys conducted by an independent survey organization. The
results of these surveys are used, along with other factors, to determine the amounts of any incentive rewards or
penalties to SCE under the PBR provisions for customer satisfaction. SCE recorded aggregate customer
satisfaction rewards of $28 million for the years 1998, 1999 and 2000. Potential customer satisfaction rewards
aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in
income by SCE. SCE also anticipated that it could be eligible for customer satisfaction rewards of about
$10 million for 2003.
SCE has been conducting an internal investigation and keeping the CPUC informed of its progress. On June 25,
2004, SCE submitted to the CPUC a PBR customer satisfaction investigation report, which concluded that employees
in the design organization of the transmission and distribution business unit deliberately altered customer
contact information in order to affect the results of customer satisfaction surveys. At least 36 design
organization personnel engaged in deliberate misconduct including alteration of customer information before the
data were transmitted to the independent survey company. Because of the apparent scope of the misconduct, SCE
proposed to refund to ratepayers all of the $12 million in PBR rewards that are attributable to the design
organization's portion of the customer satisfaction rewards for the entire PBR period (1997-2003). In addition,
during its investigation, SCE determined that it could not confirm the integrity of the method used for obtaining
customer satisfaction survey data for meter reading. Thus, SCE also proposed to refund all of the approximately
$2 million of customer satisfaction rewards associated with meter reading. SCE expects that it would refund
approximately half of the total of $14 million from customer satisfaction rewards previously received. SCE
believes it is likely that it could deal with the approximate remaining half by adjustments to the pending and
to-be-requested rewards noted above.
SCE has taken remedial action as to the customer satisfaction survey misconduct by severing the employment of
several supervisory personnel, updating system process and related documentation for survey reporting, and
implementing additional supervisory controls over data collection and processing.
The CPUC has not yet opened a formal investigation into this matter. However, it has submitted several data
requests to SCE and has requested an opportunity to interview a number of SCE employees in the design
organization. SCE is in the process of responding to those requests.
Employee Injury and Illness Reporting
In light of the problems uncovered with the customer satisfaction surveys, SCE is conducting an investigation
into the accuracy of SCE's employee injury and illness reporting. The yearly results of
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
employee injury and illness reporting to the CPUC are used to determine the amount of the incentive reward or
penalty to SCE under the PBR mechanism. Since the inception of PBR in 1997, SCE has received $20 million in
employee safety incentives for 1997 through 2000 and, based on SCE's records, may be entitled to an additional
$15 million for 2001 through 2003.
While this investigation is not yet complete, on October 21, 2004, SCE reported to the CPUC and other appropriate
regulatory agencies certain findings concerning SCE's performance under the PBR incentive mechanism for injury
and illness reporting. Under the PBR mechanism, rewards and/or penalties for the years 1997 through 2003 were
based upon a total incident rate, which included two equally weighted measures: Occupational Safety and Health
Administration (OSHA) recordable incidents and first aid incidents. The major issue disclosed in the
investigative findings to the CPUC was that SCE failed to implement an effective recordkeeping system sufficient
to capture all required data for first aid incidents. SCE's investigation also found reporting inaccuracies for
OSHA recordable incidents, but the impact of these inaccuracies did not have a material effect on the PBR
mechanism.
As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the mechanism for
any year before 2005, and it return to ratepayers the $20 million it has already received. SCE has also proposed
to withdraw the pending rewards for the 2001-2003 time frames.
SCE is taking other remedial action to address the issues identified, including, revising its organizational
structure and overall program for environmental, health and safety compliance. Additional actions, including
disciplinary action against specific employees identified as having committed wrongdoing, may result once the
entire investigation is completed, which is expected by the end of November 2004.
System Reliability
In light of the problems uncovered with the PBR mechanisms discussed above, SCE is conducting an investigation
into the third PBR metric, system reliability. Since the inception of PBR payments in 1997, SCE has received $8
million in rewards and has applied for an additional $5 million reward based on frequency of outage data for
2001. For 2003, SCE's data would result in a penalty of $5 million which has not yet been assessed.
While this investigation is not yet complete, on October 21, 2004, SCE reported to the CPUC that overall, the
reliability reporting system is working well.
Navajo Nation Litigation
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 Holding Company (Peabody) and certain of its affiliates, Salt
River Project Agricultural Improvement and Power District, and SCE arising out of the coal supply agreement for
Mohave. The complaint asserts claims for, among other things, violations of the federal Racketeer Influenced and
Corrupt Organizations 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. SCE joined Peabody's motion to strike the Navajo Nation's complaint. In addition,
SCE and other defendants filed
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
motions to dismiss. The D.C. District Court denied these motions for dismissal, except for Salt River Project
Agricultural Improvement and Power District's motion for its separate dismissal from the lawsuit.
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 in the United States Court of Federal Claims against the United States
Department of Interior. 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. Based on the
Supreme Court's analysis, on April 28, 2003, SCE and Peabody filed motions to dismiss or, in the alternative, for
summary judgment in the D.C. District Court action. On April 13, 2004, the D.C. District Court denied SCE's and
Peabody's April 2003 motions to dismiss, or in the alternative, for summary judgment. The D.C. District Court
subsequently issued a scheduling order that imposed a December 31, 2004 discovery cut-off. Pursuant to a joint
request of the parties, the D.C. District Court granted a 120-day stay of the action to allow the parties to
attempt to resolve, through facilitated negotiations, all issues associated with Mohave. The facilitated
negotiations are currently set to commence on November 8, 2004. The stay granted by the D.C. District Court is
scheduled to expire on February 5, 2005.
The United States Court of Appeals for the D.C. Circuit, acting on a suggestion on remand filed by the Navajo
Nation, held in a October 24, 2003 decision that the Supreme Court's March 4, 2003 decision was focused on three
specific statutes or regulations and therefore did not address 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 Government and the Navajo Nation both filed petitions for rehearing of the
October 24, 2003 D.C. Circuit Court decision. Both petitions were denied on March 9, 2004. On March 16, 2004,
the D.C. Circuit Court issued an order remanding the case against the Government to the Court of Federal Claims,
which conducted a status conference on May 18, 2004. As a result of the status conference discussion, the Court
of Federal Claims has ordered the Navajo Nation and the Government to brief the remaining issues following
remand. Peabody's motion to intervene as a party in the remanded Court of Federal Claims case was denied.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, the impact of
the Supreme Court's decision in the Navajo Nation's suit against the Government on this complaint, 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 $10.8 billion. SCE and other owners of San
Onofre and Palo Verde 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 United States 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
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SOUTHERN CALIFORNIA EDISON COMPANY
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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. All licensed operating
plants including San Onofre and Palo Verde are grandfathered under the applicable law.
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 $43 million per year. Insurance premiums are charged to operating expense.
Spent Nuclear Fuel
Under federal law, the United States Department of Energy (DOE) is responsible for the selection and construction
of a facility for the permanent disposal of spent nuclear fuel and high-level radioactive waste. The DOE did not
meet its obligation to begin acceptance of spent nuclear fuel not later than January 31, 1998. It is not certain
when the DOE will begin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended
delays by the DOE have led to the construction of costly alternatives and associated siting and environmental
issues. SCE has paid the DOE the required one-time fee applicable to nuclear generation at San Onofre through
April 6, 1983 (approximately $24 million, plus interest). SCE is also paying the required quarterly fee equal to
0.1(cent)-per-kWh of nuclear-generated electricity sold after April 6, 1983. On January 29, 2004, SCE, as operating
agent, filed a complaint against the DOE in the Federal Court of Claims seeking damages for DOE's failure to meet
its obligation to begin accepting spent nuclear fuel from San Onofre. The case if currently stayed pending
development in other spent nuclear fuel cases also before the Federal Court of Claims.
SCE has primary responsibility for the interim storage of spent nuclear fuel generated at San Onofre. Spent
nuclear fuel is stored in the San Onofre Units 2 and 3 spent fuel pools and the San Onofre independent spent fuel
storage installation. Movement of Unit 1 spent fuel from the Unit 3 spent fuel pool to the independent spent
fuel storage installation was completed in late 2003. Movement of Unit 1 spent fuel from the Unit 1 spent fuel
pool to the independent spent fuel storage installation was completed in late 2004. Movement of Unit 1 spent
fuel from the Unit 2 spent fuel pool to the independent spent fuel pool storage installation is scheduled to be
completed by spring 2005. With these moves, there will be sufficient space in the Unit 2 and 3 spent fuel pools
to meet plant requirements through mid-2007 and mid-2008, respectively. In order to maintain a full core
off-load capability, SCE is planning to begin moving Unit 2 and 3 spent fuel into the independent spent fuel
storage installation by late 2006.
In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed a
dry cask storage facility. Arizona Public Service, as operating agent, plans to continually load casks on a
schedule to maintain full core off-load capability for all three units.
Note 5. Mountainview Acquisition
On March 12, 2004, SCE acquired Mountainview Power Company LLC, which owns a power plant under construction in
Redlands, California. SCE has recommenced full construction of the
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
approximately $600 million project, which is expected to be completed in 2006. The construction work in progress
for this project is recorded in nonutility property on SCE's September 30, 2004 balance sheet.
Note 6. 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 the three and nine months ended September 30, 2003.
For the three months 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.
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Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations
INTRODUCTION
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, 2004 discusses material changes in the financial condition, results of
operations and other developments of Southern California Edison Company (SCE) since December 31, 2003, and as
compared to the three- and nine-month periods ended September 30, 2003. This discussion presumes that the reader
has read or has access to SCE's MD&A for the calendar year 2003 (the year-ended 2003 MD&A), which was included in
SCE's 2003 annual report to shareholders and incorporated by reference into SCE's Annual Report on Form 10-K for
the year-ended December 31, 2003.
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 and uncertainties that could cause actual future
outcomes and results of operations to be materially different from those set forth in this discussion. Important
factors that could cause actual results to differ are discussed throughout this MD&A. The following discussion
provides updated information about material developments since the issuance of the year-ended 2003 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, 2003.
This MD&A includes information about SCE, an investor-owned utility company providing electricity to retail
customers in central, coastal, and southern California. SCE is regulated by the California Public Utilities
Commission (CPUC) and the Federal Energy Regulatory Commission (FERC).
This MD&A is presented in 10 major sections. The MD&A begins with a discussion of current developments. The
remaining sections of the MD&A include: liquidity; market risk exposures; regulatory matters; other
developments; results of operations and historical cash flow analysis; acquisition; critical accounting policies;
new accounting principles; and commitments and guarantees.
CURRENT DEVELOPMENTS
2003 General Rate Case Proceeding
On July 8, 2004, the CPUC issued a final decision on SCE's 2003 General Rate Case (GRC) application. Because
processing of the 2003 GRC took longer than initially scheduled, in May 2003, the CPUC approved SCE's request to
establish a memorandum account to track the revenue requirement increase during the period between May 22, 2003
(the date a final CPUC decision was originally scheduled to be issued) and the date a final decision was
adopted. In July 2004, SCE submitted an advice filing to record the amount in this memorandum account, and
recorded an approximate $55 million pre-tax gain in the third quarter of 2004. In addition, during the third
quarter of 2004 SCE recorded approximately $48 million in pre-tax gains related to the rate recovery of 1997-1998
generation-related capital additions and the related revenue requirement. See "Regulatory Matters--Transmission
and Distribution--2003 General Rate Case Proceeding" for further details on the implementation of the 2003 GRC.
Proposed Legislation
The California Legislature submitted to the Governor of California Assembly Bill 2006, which was entitled the
"Reliable Electric Service Act." The bill proposed to affirm the obligation of utilities to plan and provide
adequate, efficient, and cost-effective supply and demand resources and would have required
Page 24
utilities to prepare a long-term resource plan to achieve a diversified portfolio of cost-effective supply and
demand resources. The Governor of California did not sign Assembly Bill 2006 into law. SCE will continue to
advocate steps to strengthen the regulatory framework to enhance assurance of utility cost recovery and to
provide a fair allocation of cost responsibility to all electricity consumers.
LIQUIDITY ISSUES
SCE's liquidity is primarily affected by under- or over-collections of procurement-related costs, collateral and
mark-to-market requirements associated with purchase power contracts, and access to capital markets or external
financings. At September 30, 2004, SCE's credit and long-term issuer ratings from Standard & Poor's and Moody's
Investors Service were BBB and Baa1, respectively. On September 17, 2004, Moody's Investors Service assigned SCE
a short-term credit rating of P2 in connection with SCE's launch of a new $700 million commercial paper program.
Standard and Poor's had previously issued SCE a short-term credit rating of A2. As of September 30, 2004, SCE
had no commercial paper outstanding.
At September 30, 2004, SCE had cash and equivalents of $188 million and long-term debt, including current
maturities, of $5.4 billion. As of September 30, 2004, SCE posted approximately $42 million ($33 million in cash
and $9 million in letters of credit) as collateral to secure its obligations under power-purchase contracts and
to transact through the California Independent System Operator (ISO) for imbalance energy. SCE's collateral
requirements can vary depending upon the level of unsecured credit extended by counterparties, the ISO's credit
requirements, changes in market prices relative to contractual commitments, and other factors. SCE has a
$700 million credit facility that expires in December 2006. As of September 30, 2004, the credit facility was not
utilized, except for $9 million supporting letters of credit as mentioned above. SCE's 2004 estimated cash
outflows consist of:
o $125 million of 5.875% bonds which were due and paid in September 2004;
o Approximately $246 million of rate reduction notes that are due at various times in 2004, but which have
a separate cost recovery mechanism approved by state legislation and CPUC decisions;
o Projected capital expenditures of $1.9 billion, including the investment in the Mountainview project and
related capital expenditures (see "Acquisition");
o Dividend payments to SCE's parent company. SCE paid cash dividends of $300 million, $145 million and
$150 million to Edison International on March 30, 2004, May 21, 2004 and September 23, 2004, respectively;
o Fuel and procurement-related costs; and
o General operating expenses.
SCE expects to meet its continuing obligations, including cash outflows for power-procurement undercollections
(if incurred), through cash and equivalents on hand, operating cash flows and short-term borrowings, when
necessary. Projected capital expenditures are expected to be financed through cash flows and the issuance of
long-term debt.
The CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International. In SCE's
most recent cost of capital proceeding, the CPUC set an authorized capital structure for SCE which included a
common equity component of 48%. SCE determines compliance with this capital structure based on a 13-month
weighted-average calculation. At September 30, 2004, SCE's 13-month weighted-average common equity component of
total capitalization was 51%. At September 30, 2004,
Page 25
SCE had the capacity to pay $230 million in additional dividends based on the 13-month weighted-average method.
Based on recorded September 30, 2004 balances, SCE's common equity to total capitalization ratio, for rate-making
purposes, was 50%. SCE had the capacity to pay $137 million of additional dividends to Edison International
based on September 30, 2004 recorded balances.
In January 2004, SCE issued $975 million of first and refunding mortgage bonds. The issuance included
$300 million of 5% bonds due in 2014, $525 million of 6% bonds due in 2034 and $150 million of floating rate bonds
due in 2006. The proceeds were used to redeem $300 million of 7.25% first and refunding mortgage bonds due March
2026, $225 million of 7.125% first and refunding mortgage bonds due July 2025, $200 million of 6.9% first and
refunding mortgage bonds due October 2018, and $100 million of junior subordinated deferrable interest debentures
due June 2044. In the first quarter of 2004, SCE remarketed approximately $550 million of pollution-control
bonds with varying maturity dates ranging from 2008 to 2040. Approximately $354 million of these
pollution-control bonds had been held by SCE since 2001 and the remaining $196 million were purchased and
reoffered in 2004. In March 2004, SCE issued $300 million of 4.65% first and refunding mortgage bonds due in
2015 and $350 million of 5.75% first and refunding mortgage bonds due in 2035. A portion of the proceeds from
the March 2004 first and refunding mortgage bond issuances were used to fund the acquisition and construction of
the Mountainview project, with the remainder of the proceeds to be used for ongoing capital expenditures for
generation, transmission and distribution facilities, and for general corporate purposes.
SCE's liquidity may be affected by, among other things, matters described in "Regulatory Matters."
MARKET RISK EXPOSURES
SCE's primary market risks include fluctuations in interest rates, generating fuel commodity prices and volume
and counterparty credit. Fluctuations in interest rates can affect earnings and cash flows. Fluctuations in
fuel prices and volumes and counterparty credit losses temporarily affect cash flows, but should not affect
earnings. See "Market Risk Exposures" in the year-ended 2003 MD&A for a complete discussion of SCE's market risk
exposures.
REGULATORY MATTERS
This section of the MD&A describes SCE's regulatory matters in three main subsections:
o generation and power procurement;
o transmission and distribution; and
o other regulatory matters.
Generation and Power Procurement
Proposed Legislation
The California Legislature submitted to the Governor of California Assembly Bill 2006, which was entitled the
"Reliable Electric Service Act." The bill proposed to affirm the obligation of utilities to plan and provide
adequate, efficient, and cost-effective supply and demand resources and would have required utilities to prepare
a long-term resource plan to achieve a diversified portfolio of cost-effective supply and demand resources. The
Governor of California did not sign Assembly Bill 2006 into law. SCE will continue to advocate steps to
strengthen the regulatory framework to enhance assurance of utility cost recovery and to provide a fair
allocation of cost responsibility to all electricity consumers.
Page 26
CPUC Litigation Settlement Agreement
As discussed in the "CPUC Litigation Settlement Agreement" disclosure in the year-ended 2003 MD&A, in October
2001, SCE and the CPUC entered into a settlement of SCE's lawsuit against the CPUC that allowed SCE to recover
$3.6 billion in past procurement-related obligations. 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 2001 CPUC settlement agreement. In
September 2002, the Ninth Circuit Court 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 Court referred to
the California Supreme Court.
In August 2003, the California Supreme Court concluded that the 2001 CPUC settlement agreement did not violate
California law in any of the respects raised by the Ninth Circuit Court. The matter was returned to the Ninth
Circuit Court for final disposition, and in December 2003, the Ninth Circuit Court unanimously affirmed the
original stipulated judgment of the federal district court. In January 2004, the Ninth Circuit Court issued its
mandate, relinquishing jurisdiction of the case and returning jurisdiction to the federal district court. No
petitions were filed within the 90-day period in which parties could seek discretionary review by the United
States Supreme Court of the federal district court's decision. Accordingly, the appeals of the stipulated
judgment approving the 2001 CPUC settlement agreement have been resolved in SCE's favor.
Energy Resource Recovery Account Proceedings
As discussed in the "Energy Resource Recovery Account Proceedings" disclosure in the year-ended 2003 MD&A, the
CPUC established the Energy Resource Recovery Account (ERRA) as the rate-making mechanism to track and recover
SCE's generation-related costs.
2004 ERRA Forecast
SCE submitted an ERRA forecast application on October 3, 2003, in which it forecast a procurement-related revenue
requirement for the 2004 calendar year of $2.3 billion. The CPUC issued a decision on April 22, 2004, approving
SCE's 2004 forecast revenue requirement and rates for both generation and distribution services.
ERRA Reasonableness Reviews
On October 3, 2003, SCE submitted its first ERRA reasonableness review application requesting that the CPUC find
its procurement-related operations during the period from September 1, 2001 through June 30, 2003 to be
reasonable. Because this is the first annual review of this activity, pursuant to new California state law, the
CPUC's interpretation and application of California state law is uncertain. Clarification is expected in a
decision in the fourth quarter of 2004. Pursuant to the assigned commissioner's scoping memo issued on
December 9, 2003, the CPUC's Office of Ratepayer Advocates (ORA) was allowed to review the accounting calculations
used in the Procurement-Related Obligations Account (PROACT) mechanism. The ORA testimony, filed on March 19,
2004, included an audit of these accounting calculations, in which ORA recommended disallowances that totaled
approximately $14 million of costs recovered through the PROACT mechanism during the period from September 1,
2001 through June 30, 2003. In April 2004, SCE reached an agreement with the ORA (subject to CPUC approval) to
reduce the PROACT disallowances to approximately $3.6 million. This amount, which is mainly comprised of ISO
grid management charges and employee-related retraining costs, would be refunded to ratepayers through a credit
to the ERRA.
In addition to its disallowance recommendations, ORA recommended that in reviewing SCE's administration of its
procurement contracts and the daily dispatch of its generation resources, the CPUC
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should perform a traditional "reasonableness review," that is, SCE should have the burden of proving that its
decisions during the record period complied with what a "reasonable manager" would have done under similar
circumstances. In its opening and reply briefs, SCE urged the CPUC to reject this recommendation, stating that
under recent California law, SCE's burden is to demonstrate that its decisions complied with the dispatch
standard that a 2002 CPUC decision had placed in SCE's approved procurement plan; this is, that SCE used the most
cost-effective mix of the total generation resources available to it, thereby minimizing the cost of delivering
electric services to its customers. SCE believes the latter standard is required by law, and is more objective
than the standard ORA advocates.
On September 27, 2004, the CPUC issued a proposed decision, adopting the SCE-ORA joint recommendation to adjust
the ERRA downward by approximately $3.6 million, and finding SCE's operations during the period from September 1,
2001 through June 30, 2003 reasonable in all other respects. However, the proposed decision adopts ORA's
position that the scope of the CPUC review of SCE's dispatch operations should include a review of procurement
transactions up to one year prior to the date of delivery. A decision on this matter is expected in the fourth
quarter of 2004.
On April 1, 2004, SCE submitted its second ERRA reasonableness review application requesting that the CPUC find
its procurement-related operations during the period from July 1, 2003 through December 31, 2003, to be
reasonable. In addition, SCE requested recovery of a $10 million reward for efficient operation of Unit 3 of the
Palo Verde Nuclear Generating Station (Palo Verde) and $5 million in electric energy transaction administration
costs.
At hearings, the ORA recommended disallowances that totaled approximately $2.6 million based on its allegation
that SCE should have made additional surplus energy sales in the month-ahead market during October and November
2003. SCE contested ORA's disallowance recommendation both on procedural grounds and on its merits. A final
decision is expected in the first quarter of 2005.
2005 ERRA Forecast
SCE submitted an ERRA forecast application on August 2, 2004, in which it forecasted a procurement-related
revenue requirement for the 2005 calendar year of $3.0 billion, an increase of $733 million over 2004. The
forecast increase is primarily due to a reduction in expected power purchases by the California Department of
Water Resources (CDWR). SCE proposed that the CPUC issue a final decision on this matter in December 2004.
Generation Procurement Proceedings
SCE resumed power procurement responsibilities for its residual-net short position (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, pursuant to CPUC orders and California statutes passed in 2002. The current
regulatory and statutory framework requires SCE to assume limited responsibilities for CDWR contracts allocated
by the CPUC, and provide full power procurement responsibilities on the basis of annual short-term procurement
plans, long-term resource plans and increased procurement of renewable resources. See "Generation Procurement
Proceedings" disclosure in the year-ended 2003 MD&A for further discussion of the matters discussed below.
Short-Term Procurement Plan
In December 2003, the CPUC adopted a 2004 short-term procurement plan for SCE. Currently, SCE is operating under
this approved short-term procurement plan. On July 9, 2004, SCE submitted minor revisions to this short-term
procurement plan, as part of its long-term resource plan filing, which is discussed below. The CPUC is expected
to consider those modifications this fall and issue a decision by the end of the year.
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Each quarter, SCE is required to file a report with the CPUC demonstrating that SCE's procurement-related
transactions associated with serving the demands of its bundled electricity customers were in conformance with
SCE's adopted short-term procurement plan. SCE has submitted seven quarterly compliance filings covering the
period from January 1, 2003 through September 30, 2004, including its third quarter 2004 compliance filing on
November 1, 2004 covering SCE's transactions for the period July 1, 2004 to September 30, 2004. To date,
however, the CPUC has only issued one resolution approving SCE's first compliance report for the period January 1,
2003 to March 31, 2003. While SCE believes that all of its procurement transactions were in compliance with its
adopted short-term procurement plan, SCE cannot predict with certainty whether or not the CPUC will agree with
SCE's interpretation regarding some elements.
Long-Term Resource Plan
On April 15, 2003, SCE filed its long-term resource plan with the CPUC that included both a preferred plan and an
interim plan. In January 2004, the CPUC issued a decision that did not adopt any long-term resource plan, but
adopted a framework for resource planning which addressed short- and long-term resource planning, as well as the
development of a resource adequacy requirement. Until the CPUC approves a long-term resource plan for SCE, SCE
will operate under its interim resource plan.
On April 1, 2004, the CPUC instituted a resource planning proceeding that will coordinate consideration of
long-term resource plans. On July 9, 2004, SCE filed testimony on its long-term resource plan, which includes a
substantial commitment to cost-effective energy efficiency and an advanced load-control program. The long-term
resource plan presented four procurement plan scenarios: a medium-load plan scenario, a high-load plan scenario,
a low-load plan scenario, and a CDWR-variant scenario. Hearings on the long-term procurement plans of SCE,
Pacific Gas and Electric Company (PG&E) and San Diego Gas & Electric Company (SDG&E) were held between August 30,
2004 and September 24, 2004. A decision is expected by year-end 2004.
On October 28, 2004, the CPUC issued a decision clarifying the January 2004 decision. The recent decision
requires load serving entities to ensure that adequate resources have been contracted for in order to meet that
entity's peak forecasted energy resource demand and an additional planning reserve margin of 15-17% of that peak
load by June 1, 2006. Currently, the decision requires SCE to demonstrate that it has contracted 90% of its
May-September 2006 resource adequacy requirement by September 30, 2005. As the May-September period approaches,
SCE will be required to fill out the remaining 10% of its resource adequacy requirement one month in advance of
expected need. The October 28, 2004 decision also clarified that although the first compliance filing will only
cover May-September 2006, the 15-17% planning reserve margin is a year-round requirement. In its October
decision, the CPUC also decided that long-term CDWR contracts allocated to the investor-owned utilities during
the 2001 energy crisis are to be fully counted for resource adequacy purposes, and that any deliverability
standards developed during subsequent phases will be applied to such contracts. These deliverability standards,
as well as a wide range of other issues, including scheduling, load forecasting and deliverability generally,
will be addressed in a separate phase of the proceeding which is expected to be completed by mid-2005. SCE
expects to meet its resource adequacy requirements by the deadlines set forth in the decision.
Procurement of Renewable Resources
As part of SCE's resumption of power procurement, and in accordance with a California statute passed in 2002, SCE
is required to increase its procurement of renewable resources by at least 1% of its annual electricity sales per
year so that 20% of its annual electricity sales are procured from renewable resources by no later than
December 31, 2017. In June 2003, the CPUC issued a decision adopting preliminary rules and guidance on renewable
procurement-related issues, including penalties for noncompliance with renewable procurement targets. In June
2004, the CPUC issued two decisions adopting additional rules
Page 29
on renewable procurement: a decision adopting standard contract terms and conditions and a decision adopting a
market price methodology. In July 2004, the CPUC issued a decision adopting criteria for the selection of
least-cost and best-fit renewable resources.
SCE received bids for renewable resource contracts in response to a solicitation it made in August 2003 and is
conducting negotiations with a short list of bidders regarding potential procurement contracts. The procedures
for measuring renewable procurement are still being developed by the CPUC. Based upon the current regulatory
framework, SCE anticipates that it will, even without new renewable procurement contracts, comply with renewable
procurement mandates through at least 2005. Beyond 2005, SCE will either need to sign new contracts and/or
extend existing renewable QF contracts.
CDWR Power Purchases and Revenue Requirement Proceedings
In accordance with an emergency order by the Governor of California, the CDWR began making emergency power
purchases for SCE's customers on January 17, 2001. The CDWR's total statewide power charge and bond charge
revenue requirements are allocated by the CPUC among the customers of SCE, PG&E and SDG&E. Amounts billed to and
collected from SCE's customers for electric power purchased and sold by the CDWR are remitted directly to the
CDWR and are not recognized as revenue by SCE.
Currently, the CPUC is considering the appropriate methodology for allocating the CDWR's power charge revenue
requirement for 2004 through 2013. PG&E, TURN, and SCE submitted a settlement agreement, which is supported by
ORA, advocating that the costs of each of the CDWR's long-term contracts be allocated directly to the
investor-owned utility bearing operational responsibility for the contract (a cost-follow-contracts allocation),
with an annual adjustment to ensure that each investor-owned utility's customers bear an equitable portion of the
above-market costs burden of those contracts. The methodology proposed in the settlement agreement also
facilitates the appropriate incentives for operating and administering the contracts.
The CPUC issued four draft decisions that would reject the proposed settlement agreement. Two of those draft
decisions would retain the cost-follow-contracts allocation of the avoidable costs of CDWR contracts, but would
allocate 43.75% of the unavoidable costs, as opposed to the above-market burden, to the customers of PG&E, 43.75%
to those of SCE, and 12.5% of the unavoidable costs to the customers of SDG&E. While such an allocation would
lower the portion of the total power charge revenue requirement that SCE's customers would bear for the 10-year
period, it would institute a methodology that SCE contends does not provide the appropriate contract
administration incentives to investor-owned utilities.
A third draft decision would also retain the cost-follow-contracts allocation of the avoidable costs of CDWR
contracts, but would allocate 42.2% of the unavoidable costs to the customers of PG&E, 47.5% to those of SCE, and
only 10.3% of the unavoidable costs to the customers of SDG&E.
Finally, a fourth draft decision, while rejecting the settlement agreement, would adopt some of its key
attributes. It would adopt a cost-follow-contracts allocation of the avoidable costs of CDWR contracts, and
allocate the above-market costs associated with the contracts: 44.8% to PG&E's customers, 45.3% to SCE's
customers, and 9.9% to SDG&E's customers. PG&E, TURN and SCE have urged the CPUC to adopt this final draft
decision, modified to allocate a higher share to the customers of SDG&E.
A final decision on this matter is expected before year-end 2004.
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Mohave Generating Station and Related Proceedings
As discussed in the "Mohave Generating Station and Related Proceedings" disclosure in the year-ended 2003 MD&A,
on May 17, 2002, SCE filed an application with the CPUC to address certain issues (mainly coal and slurry-water
supply issues) facing the future extended operation of Mohave Generating Station (Mohave), which is partly owned
by SCE. Until the post-2005 coal and water supply uncertainty is resolved, SCE and other Mohave co-owners cannot
determine whether it would be cost-effective to make the approximately $1.1 billion in Mohave-related investments
(SCE's share is $605 million), including the installation of pollution-control equipment that must be put in
place in order for Mohave to continue to operate beyond 2005, pursuant to a 1999 consent decree concerning air
quality.
SCE and other parties submitted further testimony and made various other filings in 2003 in SCE's application
proceeding. Pursuant to the assigned administrative law judge's March 9, 2004 ruling, on April 16, 2004, SCE
updated its position and testimony on cost data and, where data are unavailable, cost estimates for Mohave on the
following options: (1) the cost of permanent shutdown; (2) the cost of installation of required pollution
controls and related capital improvements to allow the facility to continue as a coal-fired plant beyond 2005;
(3) if option 2 is undertaken, the cost of temporary shutdown for complete installation of pollution controls, and
any costs related to restarting the facility; and (4) other alternatives and their costs. SCE's testimony
presented a summary of work performed to date and provided an update on the status of the coal and water supply
issues. The testimony also stated that SCE does not now have detailed cost projections for any of the cost
categories identified in the March 9, 2004 ruling due to the uncertainties remaining on these issues. The
testimony reiterated SCE's belief that, even if the coal and water supply issues can be satisfactorily resolved
in the near future, thereby avoiding a permanent shutdown, a temporary shutdown of at least three years is
likely.
On October 20, 2004, the CPUC issued a proposed decision which, among other things: (1) directed SCE to continue
negotiations regarding the post-2005 coal and water supply; (2) directed SCE to conduct a study of potential
alternatives to Mohave including solar generation and coal gasification; and (3) provided an opportunity for SCE
to recover in future rates certain Mohave-related costs that SCE has already incurred or is expected to incur by
2006, including certain preliminary engineering costs, water study costs and the costs of the study of Mohave
alternatives. A final decision is not expected before December 2004.
In parallel with the CPUC proceeding, negotiations have continued among the relevant parties in an effort to
resolve the coal and water supply issues. In September 2004, the parties reached agreement on certain "key
principles" related to the study and possible development of a potential alternative water supply, and the
parties agreed to retain a professional mediator for further negotiations, but no further resolution has been
reached.
The outcome of the coal and water negotiations and SCE's application are not expected to impact Mohave's
operation through 2005, but the presence or absence of Mohave as an available resource beyond 2005 could have a
major impact on SCE's long-term resource plan. The outcome of this matter is not expected to have a material
impact on earnings.
San Onofre Nuclear Generating Station Proceedings and Related Matters
Steam Generator Proceedings
As discussed in the "San Onofre Steam Generators" disclosure in the year-ended 2003 MD&A, on February 27, 2004,
SCE filed an application with the CPUC in which it asked the CPUC to issue a decision by July 2005, finding that
it is reasonable for SCE to replace the San Onofre Nuclear Generating Station (San Onofre) Unit 2 and 3 steam
generators and establishing appropriate ratemaking for the replacement costs. In this filing, SCE also asked the
CPUC for approval to establish a memorandum
Page 31
account for recovery of up to $50 million in costs to be incurred in connection with entering into contracts for
steam generator fabrication prior to the final CPUC decision. In June 2004, the CPUC established a schedule
providing for a final CPUC decision in September 2005. In July 2004, the CPUC denied SCE's request to establish
the memorandum account.
On September 30, 2004, SCE entered into a contract for steam generator fabrication with Mitsubishi Heavy
Industries America. By the time of the CPUC's scheduled decision in September 2005, SCE anticipates that it will
have committed approximately $50 million to steam generator fabrication and associated project costs. SCE will
seek recovery of these costs.
Under the San Onofre operating agreement among the co-owners, a co-owner may elect to reduce its ownership share
in lieu of paying its share of the cost of repairing an "operating impairment," as such term is defined in the
San Onofre operating agreement. SCE has declared an "operating impairment" in connection with the need for steam
generator replacement. SDG&E and the City of Anaheim have elected to reduce their respective 20% and 3.16%
ownership shares rather than participate in the steam generator replacement project. The other co-owner, the
City of Riverside (which owns 1.79% of the units), has elected to participate in the project. If steam generator
replacement proceeds, upon completion, SDG&E's and the City of Anaheim's ownership shares of San Onofre Units 2
and 3 will be reduced in accordance with the formula set forth in the operating agreement. SCE and the City of
Anaheim agree on application of the formula. Utilizing the agreed-upon approach would reduce the City of
Anaheim's share of San Onofre Units 2 and 3 to zero percent upon completion of the steam generator replacement.
SCE and SDG&E do not agree on the application of the formula. SCE believes SDG&E's ownership share would be
reduced from 20% to zero percent. SDG&E's believes its ownership share would be reduced from 20% to 14%. As a
result, the application of the formula is subject to arbitration which SCE and SDG&E are attempting to schedule
for early 2005.
The transfer of all or any portion of SDG&E's and the City of Anaheim's respective ownership share as a result of
their election not to participate in steam generator replacement will require Nuclear Regulatory Commission
approval. The transfer of all or any portion of SDG&E's ownership share will require CPUC approval.
San Onofre Reactor Vessel Heads
During the ongoing San Onofre Unit 3 refueling outage that began on September 28, 2004, SCE conducted a planned
inspection of the Unit 3 reactor vessel head and found indications of degradation. Although the degradation is
far below the level at which leakage would occur, SCE plans to make repairs during the current outage using
readily available tooling and a Nuclear Regulatory Commission-approved repair technique. While this is San
Onofre's first experience of this kind of degradation to the reactor vessel head, the detection and repair of
similar degradation is now common in the industry. SCE plans to replace the Unit 2 and 3 reactor vessel heads
during the planned refueling outages in 2009-2010.
San Onofre Pressurizer Heater Sleeve Replacement
San Onofre Units 2 and 3 each include a pressurizer tank that contains 30 heater penetrations fabricated from the
same material used in the steam generator tubes. These penetrations, also known as sleeves, are 13-inch long
sections of pipe welded into the bottom of the pressurizer. During the current Unit 3 outage, SCE performed
inspections of two sleeves and found evidence of degradation. Degradation of the pressurizer sleeves has been a
concern in the nuclear industry for some time, and SCE had been planning to replace all of the sleeves in both
units during their next scheduled refueling outages in 2005 and 2006, respectively. With the discovery of sleeve
degradation, SCE has decided to move the planned replacement of all 30 of Unit 3's sleeves forward from 2006 into
the current outage. This extra work will lengthen the outage from 55 days to the range of 95 to 110 days. The
unit is expected to return to service
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in late December 2004 or January 2005. This additional repair work will cost approximately $9 million. The CPUC
will review the reasonableness of outage-related capital costs and replacement power costs in future rate-making
proceedings. SCE believes the costs are reasonable, recovery of the costs should be authorized, and the
acceleration of the needed repairs should not impact earnings.
Transmission and Distribution
2003 General Rate Case Proceeding
On May 3, 2002, SCE filed its application for a 2003 GRC, requesting an increase of $286 million in SCE's base
rate revenue requirement, which was subsequently revised to an increase of $251 million. The application also
proposed an estimated base rate revenue decrease of $78 million in 2004, and a subsequent increase of
$116 million in 2005. The forecast reduction in 2004 was largely attributable to the expiration of the San Onofre
incremental cost incentive pricing (ICIP) rate-making mechanism at year-end 2003 and a forecast of increased
sales.
The CPUC issued a final decision on SCE's 2003 GRC application on July 8, 2004, authorizing an annual increase of
approximately $73 million in base rates, retroactive to May 22, 2003 (the date a final CPUC decision was
originally scheduled to be issued). The decision also authorized a base rate revenue decrease of $49 million in
2004, and a subsequent increase of $84 million in 2005. During the second quarter of 2004, SCE recorded pre-tax
net regulatory adjustments of $180 million as a result of the implementation of the 2003 GRC decision, primarily
relating to the recognition of revenue from the rate recovery of pension contributions during the time period
that the pension plan was fully funded, the resolution of the allocation of costs between transmission and
distribution for 1998 through 2000, partially offset by the deferral of revenue previously collected during the
ICIP mechanism for dry cask storage. The adjustments were included in the caption "provisions for regulatory
adjustment clauses--net" on the income statement. See "Results of Operations and Historical Cash Flow
Analysis--Results of Operations" for further discussion.
Because processing of the GRC took longer than initially scheduled, in May 2003, the CPUC approved SCE's request
to establish a memorandum account to track the revenue requirement increase during the period between May 22,
2003 and the date a final decision was adopted. In July 2004, SCE submitted an advice filing to record the
amount in this memorandum account and recorded an approximate $55 million pre-tax gain in the third quarter of
2004 included in the caption "operating revenue" on the income statement. In addition, during the third quarter
of 2004 SCE recorded approximately $48 million in pre-tax gains related to the 1997-1998 generation-related
capital additions ($31 million, which is included in the caption "provisions for regulatory adjustment
clauses--net" on the income statement) and the related rate recovery ($17 million, which is included in the caption
"operating revenue" on the income statement). See "Results of Operations and Historical Cash Flow
Analysis--Results of Operations" for further discussion.
The amount recorded in the GRC memorandum account will be recovered in rates together with the 2004 revenue
requirement authorized by the CPUC in the GRC decision. The GRC rate increase was combined with other rate
changes from pending rate proceedings and became effective August 5, 2004.
2006 General Rate Case Proceeding
On August 20, 2004, SCE submitted a notice of intent to file an application for a 2006 GRC. SCE expects to ask
the CPUC to authorize a $396 million increase in base revenue requirement in 2006, primarily for capital
expenditures to accommodate load growth and replace aging distribution systems. SCE also expects to ask the CPUC
to authorize continuation of SCE's existing post-test year rate-making mechanism, which would result in base rate
revenue increases of $157 million and $140 million in 2007 and 2008, respectively. If the CPUC approves these
requested increases and allocates them to ratepayer
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groups on a system average percentage change basis, the total increase over current base rates is estimated to be
10.8%. SCE anticipates filing its 2006 GRC application in December 2004.
2005 Cost of Capital
SCE's annual cost of capital applications with the CPUC are required to be filed in May of each year, with
decisions rendered in such proceedings becoming effective January 1 of the following year. On May 10, 2004, SCE
filed an application requesting the CPUC to maintain for 2005 the currently authorized 11.60% return on common
equity for SCE's CPUC-jurisdictional assets. SCE requested a change in the authorized capital structure to
reflect the debt equivalence of power-purchase agreements, and revised returns on long-term debt and preferred
stock. The request would result in a decrease in revenue requirement of approximately $28 million. A final
decision on this matter is expected in December 2004.
Electric Line Maintenance Practices Proceeding
In August 2001, the CPUC issued an order instituting investigation 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, which alleged a pattern of noncompliance with the CPUC's general orders for the maintenance
of electric lines for 1998-2000.
In an April 22, 2004 decision, the CPUC imposed minor penalties ($656,000) related to SCE's overhead and
underground electric line maintenance practices for failing to make repairs within a reasonable amount of time.
The decision provides SCE with more flexibility in scheduling inspections, but requires SCE to meet and confer
with the CPUC staff on several issues, including revisions to its maintenance priority system and possible
alternatives to the existing high voltage signage requirements.
Transmission Proceeding
In August and November 2002, the FERC issued opinions affirming a September 1999 administrative law judge
decision to disallow, among other things, recovery by SCE and the other California public utilities of costs
reflected in network transmission rates associated with ancillary services and losses incurred by the utilities
in administering existing wholesale transmission contracts after implementation of the restructured California
electric industry. SCE has incurred approximately $85 million of these unrecovered costs since 1998. After the
three California utilities appealed the decisions to the United States Court of Appeals for the D.C. Circuit, the
FERC filed a motion with the D.C. Circuit Court seeking voluntary remand to permit issuance of a further order.
On February 12, 2004, the D.C. Circuit Court granted the FERC's motion and remanded the record back to the FERC
for further consideration. On May 6, 2004, the FERC issued its order reaffirming its earlier decisions. SCE and
the other two California utilities are pursuing the appeal before the D.C. Circuit Court, and filed their opening
briefs with the D.C. Circuit Court on October 12, 2004.
Wholesale Electricity and Natural Gas Markets
In 2000, the FERC initiated an investigation into the justness and reasonableness of rates charged by sellers of
electricity in the California Power Exchange (PX) and ISO markets. On March 26, 2003, the FERC staff issued a
report concluding that there had been pervasive gaming and market manipulation of both the electric and natural
gas markets in California and on the West Coast during 2000-2001 and describing many of the techniques and
effects of that market manipulation. SCE is participating in several related proceedings seeking recovery of
refunds from sellers of electricity and natural gas who manipulated the electric and natural gas markets. Under
the 2001 CPUC settlement agreement, mentioned in "--Generation and Power Procurement--CPUC Litigation Settlement
Agreement," 90% of
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any refunds actually realized by SCE will be refunded to customers, except for the El Paso Natural Gas Company
settlement agreement discussed below.
El Paso Natural Gas Company (El Paso) entered into a settlement agreement with parties to a class action lawsuit
(including SCE, PG&E and the State of California) settling claims stated in proceedings at the FERC and in San
Diego County Superior Court that El Paso had manipulated interstate capacity and engaged in other anticompetitive
behavior in the natural gas markets in order to unlawfully raise gas prices at the California border in
2000-2001. The United States District Court has issued an order approving the stipulated judgment and the
settlement agreement has become effective. Pursuant to a CPUC decision, SCE will refund to customers amounts
received under the terms of the El Paso settlement (net of legal and consulting costs) through its ERRA
mechanism. In June 2004, SCE received its first settlement payment of $76 million. Approximately $66 million of
this amount was credited to purchased power expense, and will be refunded to SCE's ratepayers through the ERRA
over the next 12 months and the remaining $10 million was used to offset SCE's incurred legal costs. Additional
settlement payments totaling approximately $134 million are due from El Paso over a 20-year period. Amounts
El Paso refunds to the CDWR will result in reductions in the CDWR's revenue requirement allocated to SCE in
proportion to SCE's share of the CDWR's power charge revenue requirement.
On July 2, 2004, the FERC approved a settlement agreement between SCE, SDG&E and PG&E and The Williams Cos. and
Williams Power Company, providing for approximately $140 million in refunds and other payments to the settling
purchasers and others against some of Williams' power charges in 2000-2001. On August 2, 2004, SCE received its
approximately $37 million share of the refunds and other payments under the Williams settlement.
On April 26, 2004, SCE, PG&E, SDG&E and several California state governmental entities agreed to settlement terms
with West Coast Power, LLC and its owners, Dynegy Inc. and NRG Energy, Inc. (collectively, Dynegy). The
settlement terms provide for refunds and other payments totaling $285 million, with a proposed allocation to SCE
of approximately $40 million. The Dynegy settlement terms were submitted to the FERC for its approval on
June 28, 2004. The FERC is expected to act on the Dynegy settlement before year-end 2004.
On July 12, 2004, SCE, PG&E, SDG&E and several governmental entities agreed to settlement terms with Duke Energy
Corporation and a number of its affiliates. The settlement terms agreed to with the Duke parties provide for
refunds and other payments totaling in excess of $200 million, with a proposed allocation to SCE of approximately
$45 million. The Duke settlement was submitted to the FERC for its approval on October 1, 2004.
The exact manner in which net settlement proceeds under the Duke, Williams and Dynegy settlements will be
refunded to customers is expected to be the subject of a future CPUC determination. Any settlement amounts
received have been deferred, pending a final decision.
Other Regulatory Matters
Catastrophic Event Memorandum Account
As discussed in the "Catastrophic Event Memorandum Account" disclosure in the year-ended 2003 MD&A, the
catastrophic event memorandum account (CEMA) is a CPUC-authorized mechanism that allows SCE to immediately start
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. SCE currently has these
memorandum accounts for the bark beetle emergency and the fires that occurred in SCE territory in October 2003.
As of September 30, 2004, the bark beetle CEMA had a balance of $106 million and the fire-related CEMA had a
balance of $11 million. SCE submitted an advice filing with the CPUC in June 2004 to recover approximately
$18 million in bark beetle-related
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costs incurred in 2003. On September 23, 2004, the CPUC issued a resolution on SCE's advice filing granting
recovery of the majority of the $18 million bark beetle related costs recorded in 2003. The CPUC disallowed
approximately $500,000 in recorded costs based on the assertion that such costs were already recovered in rates
under SCE's routine line-clearing program. The CPUC also modified its original authorization and now requires
future bark beetle CEMA filings to be applications instead of advice letters. SCE estimates that it will spend
approximately $135 million on this project in 2004 and approximately $45 million in 2005. SCE will submit an
application to recover the 2004 costs in 2005. SCE expects to submit an application with the CPUC in the fourth
quarter of 2004 to seek recovery of the fire-related costs.
Holding Company Proceeding
In April 2001, the CPUC issued an order instituting investigation that reopened the past CPUC decisions
authorizing utilities to form holding companies and initiated an investigation into, among other things:
(1) whether the holding companies violated CPUC requirements to give first priority to the capital needs of their
respective utility subsidiaries; (2) any additional suspected violations of laws or CPUC rules and decisions; and
(3) whether additional rules, conditions, or other changes to the holding company decisions are necessary.
On January 9, 2002, the CPUC issued an interim decision interpreting the CPUC requirement that the holding
companies give first priority to the capital needs of their respective utility subsidiaries. The decision stated
that, at least under certain circumstances, holding companies are required to infuse all types of capital into
their respective utility subsidiaries when necessary to fulfill the utility's obligation to serve its customers.
The decision did not determine whether any of the utility holding companies had violated this requirement,
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 requirement 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 in California state court
requesting a review of the CPUC's decisions with regard to first priority requirements, and Edison International
filed a petition for a review of the CPUC decision asserting jurisdiction over holding companies. PG&E and SDG&E
and their respective holding companies filed similar challenges, and all cases were transferred to the First
District Court of Appeal in San Francisco.
On May 21, 2004, the Court of Appeal issued its decision in the two consolidated cases, and denied the utilities'
and their holding companies' challenges to both CPUC decisions. The Court of Appeal held that the CPUC has
limited jurisdiction to enforce in a CPUC proceeding the conditions agreed to by holding companies incident to
their being granted authority to assume ownership of a CPUC-regulated utility. The Court of Appeal held that the
CPUC's decision interpreting the first priority requirement was not reviewable because the CPUC had not made any
ruling that any holding company had violated the first priority requirement. However, the Court of Appeal
suggested that if the CPUC or any other authority were to rule that a utility or holding company violated the
first priority requirement, the utility or holding company would be permitted to challenge both the finding of
violation and the underlying interpretation of the first priority requirement itself. On June 30, 2004, Edison
International and the other utility holding companies filed with the California Supreme Court a petition for
review of the Court of Appeal decision as to jurisdiction over holding companies, but they and the utilities did
not file a challenge to the decision as to the first priority issue. On September 1, 2004, the California
Supreme Court denied the petition for review. The Court of Appeal's decision, as to jurisdiction, is now final.
The original order instituting the investigation into whether the utilities and their holding companies have
complied with CPUC decisions and applicable statutes remains in effect, and the CPUC could initiate
Page 36
further proceedings as to any of the issues mentioned in the first paragraph above. It is uncertain whether or
when the CPUC would do so.
Investigations Regarding Performance Incentive Rewards
SCE is eligible under its CPUC-approved performance-based ratemaking (PBR) mechanism to earn rewards or penalties
based on its performance in comparison to CPUC-approved standards of customer satisfaction, employee injury and
illness reporting, and system reliability.
SCE has been conducting investigations into its performance under these PBR mechanisms and has reported to the
CPUC certain findings of misconduct and misreporting as further discussed below. As a result of the reported
events, the CPUC could institute its own proceedings to determine whether and in what amounts to order refunds or
disallowances of past and potential PBR rewards for customer satisfaction, injury and illness reporting, and
system reliability portions of PBR. The CPUC also may consider whether to impose additional penalties on SCE.
SCE cannot predict with certainty the outcome of these matters or estimate the potential amount of refunds,
disallowances, and penalties that may be required.
Customer Satisfaction
SCE received two letters in 2003 from one or more anonymous employees alleging that personnel in the service
planning group of SCE's transmission and distribution business unit altered or omitted data in attempts to
influence the outcome of customer satisfaction surveys conducted by an independent survey organization. The
results of these surveys are used, along with other factors, to determine the amounts of any incentive rewards or
penalties to SCE under the PBR provisions for customer satisfaction. SCE recorded aggregate customer
satisfaction rewards of $28 million for the years 1998, 1999 and 2000. Potential customer satisfaction rewards
aggregating $10 million for the years 2001 and 2002 are pending before the CPUC and have not been recognized in
income by SCE. SCE also anticipated that it could be eligible for customer satisfaction rewards of about
$10 million for 2003.
SCE has been conducting an internal investigation and keeping the CPUC informed of its progress. On June 25,
2004, SCE submitted to the CPUC a PBR customer satisfaction investigation report, which concluded that employees
in the design organization of the transmission and distribution business unit deliberately altered customer
contact information in order to affect the results of customer satisfaction surveys. At least 36 design
organization personnel engaged in deliberate misconduct including alteration of customer information before the
data were transmitted to the independent survey company. Because of the apparent scope of the misconduct, SCE
proposed to refund to ratepayers all of the $12 million in PBR rewards that are attributable to the design
organization's portion of the customer satisfaction rewards for the entire PBR period (1997-2003). In addition,
during its investigation, SCE determined that it could not confirm the integrity of the method used for obtaining
customer satisfaction survey data for meter reading. Thus, SCE also proposed to refund all of the approximately
$2 million of customer satisfaction rewards associated with meter reading. SCE expects that it would refund
approximately half of the total of $14 million from customer satisfaction rewards previously received. SCE
believes it is likely that it could deal with the approximate remaining half by adjustments to the pending and
to-be-requested rewards noted above.
SCE has taken remedial action as to the customer satisfaction survey misconduct by severing the employment of
several supervisory personnel, updating system process and related documentation for survey reporting, and
implementing additional supervisory controls over data collection and processing.
The CPUC has not yet opened a formal investigation into this matter. However, it has submitted several data
requests to SCE and has requested an opportunity to interview a number of SCE employees in the design
organization. SCE is in the process of responding to those requests.
Page 37
Employee Injury and Illness Reporting
In light of the problems uncovered with the customer satisfaction surveys, SCE is conducting an investigation
into the accuracy of SCE's employee injury and illness reporting. The yearly results of employee injury and
illness reporting to the CPUC are used to determine the amount of the incentive reward or penalty to SCE under
the PBR mechanism. Since the inception of PBR in 1997, SCE has received $20 million in employee safety
incentives for 1997 through 2000 and, based on SCE's records, may be entitled to an additional $15 million for
2001 through 2003.
While this investigation is not yet complete, on October 21, 2004, SCE reported to the CPUC and other appropriate
regulatory agencies certain findings concerning SCE's performance under the PBR incentive mechanism for injury
and illness reporting. Under the PBR mechanism, rewards and/or penalties for the years 1997 through 2003 were
based upon a total incident rate, which included two equally weighted measures: OSHA recordable incidents and
first aid incidents. The major issue disclosed in the investigative findings to the CPUC was that SCE failed to
implement an effective recordkeeping system sufficient to capture all required data for first aid incidents.
SCE's investigation also found reporting inaccuracies for OSHA recordable incidents, but the impact of these
inaccuracies did not have a material effect on the PBR mechanism.
As a result of these findings, SCE proposed to the CPUC that it not collect any reward under the mechanism for
any year before 2005, and it return to ratepayers the $20 million it has already received. SCE has also proposed
to withdraw the pending rewards for the 2001-2003 time frames.
SCE is taking other remedial action to address the issues identified, including revising its organizational
structure and overall program for environmental, health and safety compliance. Additional actions, including
disciplinary action against specific employees identified as having committed wrongdoing, may result once the
entire investigation is completed, which is expected by the end of November 2004.
System Reliability
In light of the problems uncovered with the PBR mechanisms discussed above, SCE is conducting an investigation
into the third PBR metric, system reliability. Since the inception of PBR payments in 1997, SCE has received
$8 million in rewards and has applied for an additional $5 million reward based on frequency of outage data for
2001. For 2003, SCE's data would result in a penalty of $5 million which has not yet been assessed.
While this investigation is not yet complete, on October 21, 2004, SCE reported to the CPUC that overall, the
reliability reporting system is working well.
OTHER DEVELOPMENTS
Electric and Magnetic Fields
As discussed in the "Electric and Magnetic Fields" disclosure in the year-ended 2003 MD&A, certain issues have
been raised regarding electric and magnetic fields that naturally result from the generation, transmission,
distribution and use of electricity. On August 19, 2004, the CPUC issued an order instituting a rulemaking to
update the CPUC's policies and procedures related to electromagnetic fields emanating from regulated utility
facilities. Comments to clarify the issues to be addressed in the proceeding are due by December 31, 2004. SCE
cannot predict with certainty the outcome of this proceeding.
Page 38
Employee Compensation and Benefit Plans
In April 1999, SCE adopted a cash balance feature for its pension plan. On July 31, 2003, a federal district
court held that the formula used in a cash balance pension plan created by International Business Machine
Corporation (IBM) in 1999 violated the age discrimination provisions of the Employee Retirement Income Security
Act of 1974. In its decision, the federal district court set forth a standard for cash balance pension plans.
This decision, however, conflicts with the decisions from two other federal district courts (including a post-IBM
decision issued in June 2004) and with the proposed regulations for cash balance pension plans issued by the
Internal Revenue Service (IRS) in December 2002. On February 12, 2004, the same federal district court ruled
that IBM must make back payments to workers covered under this plan. IBM has indicated that it will appeal both
decisions to the United States Court of Appeals for the Seventh Circuit. On September 15 and September 29, 2004,
IBM announced settlements of some of the claims, but stated the company would continue to appeal the two claims
relating to age discrimination. The settlements also cap the potential damages IBM will face if it loses its
appeal on the age discrimination issues. The formula for SCE's cash balance pension plan does not meet the
standard set forth in the federal district court's July 31, 2003 decision. SCE cannot predict with certainty the
effect of the two IBM decisions on SCE's cash balance pension plan.
Environmental Matters
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.
Environmental Remediation
SCE records its environmental remediation liabilities when site assessments and/or remedial actions are probable
and a range of reasonably likely cleanup costs can be estimated. SCE reviews its sites and measures the
liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently
available information, including existing technology, presently enacted laws and regulations, experience gained
at similar sites, and the probable level of involvement and financial condition of other potentially responsible
parties. These estimates include costs for site investigations, remediation, operations and maintenance,
monitoring and site closure. Unless there is a probable amount, SCE records the lower end of this reasonably
likely range of costs (classified as other long-term liabilities) at undiscounted amounts.
SCE's recorded estimated minimum liability to remediate its 24 identified sites is $88 million. The ultimate
costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties
inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable
data for identified sites; the varying costs of alternative cleanup methods; developments resulting from
investigatory studies; the possibility of identifying additional sites; and the time periods over which site
remediation is expected to occur. SCE believes that, due to these uncertainties, it is reasonably possible that
cleanup costs could exceed its recorded liability by up to $131 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 $30 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
Page 39
regulatory asset of $61 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 $13 million to $25 million. Recorded costs for the twelve months
ended September 30, 2004 were $17 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
Edison International has reached a tentative settlement with the IRS on tax issues and pending affirmative claims
relating to its 1991 to 1993 tax years currently under appeal. This settlement, which will be finalized in 2005,
is expected to result in a net earnings benefit for SCE of approximately $50 million.
In August 2002, Edison International received a notice from the IRS 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 asserted tax deficiencies are timing differences and, therefore, amounts ultimately
paid (exclusive of interest and penalties), if any, would benefit SCE as future tax deductions. SCE believes
that it has meritorious legal defenses to deficiencies asserted against it and believes that the ultimate outcome
of these matters will not result in a material impact on SCE's consolidated results of operations or financial
position.
In April 2004, Edison International filed California Franchise Tax amended returns for tax years 1997 through
2002 to abate the possible imposition of new California penalty provisions on transactions that may be considered
as listed or substantially similar to listed transactions described in an IRS notice that was published in 2001.
These transactions include a transaction entered into by an SCE subsidiary, which may be considered substantially
similar to a listed transaction described by the IRS as a contingent liability company. Edison International
filed these amended returns under protest retaining its appeal rights and SCE believes that Edison International
will prevail in an outcome that will not have a material financial impact on SCE.
Navajo Nation Litigation
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 Holding Company (Peabody) and certain of its affiliates, Salt
River Project Agricultural Improvement and Power District, and SCE arising out of the coal supply agreement for
Mohave. The complaint asserts claims for, among other things, violations of the federal Racketeer Influenced and
Corrupt Organizations 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
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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. SCE joined Peabody's motion to strike
the Navajo Nation's complaint. In addition, SCE and other defendants filed motions to dismiss. The D.C.
District Court denied these motions for dismissal, except for Salt River Project Agricultural Improvement and
Power District's motion for its separate dismissal from the lawsuit.
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 in the United States Court of Federal Claims against the United States
Department of Interior. 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. Based on the
Supreme Court's analysis, on April 28, 2003, SCE and Peabody filed motions to dismiss or, in the alternative, for
summary judgment in the D.C. District Court action. On April 13, 2004, the D.C. District Court denied SCE's and
Peabody's April 2003 motions to dismiss or, in the alternative, for summary judgment. The D.C. District Court
subsequently issued a scheduling order that imposed a December 31, 2004 discovery cut-off. Pursuant to a joint
request of the parties, the D.C. District Court granted a 120-day stay of the action to allow the parties to
attempt to resolve, through facilitated negotiations, all issues associated with Mohave. The facilitated
negotiations are currently set to commence on November 8, 2004. The stay granted by the D.C. District Court is
scheduled to expire on February 5, 2005.
The United States Court of Appeals for the D.C. Circuit, acting on a suggestion on remand filed by the Navajo
Nation, held in a October 24, 2003 decision that the Supreme Court's March 4, 2003 decision was focused on three
specific statutes or regulations and therefore did not address 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 Government and the Navajo Nation both filed petitions for rehearing of the
October 24, 2003 D.C. Circuit Court decision. Both petitions were denied on March 9, 2004. On March 16, 2004,
the D.C. Circuit Court issued an order remanding the case against the Government to the Court of Federal Claims,
which conducted a status conference on May 18, 2004. As a result of the status conference discussion, the Court
of Federal Claims has ordered the Navajo Nation and the Government to brief the remaining issues following
remand. Peabody's motion to intervene as a party in the remanded Court of Federal Claims case was denied.
SCE cannot predict with certainty the outcome of the 1999 Navajo Nation's complaint against SCE, the impact of
the Supreme Court's decision in the Navajo Nation's suit against the Government on this complaint, or the impact
of the complaint on the operation of Mohave beyond 2005.
RESULTS OF OPERATIONS AND HISTORICAL CASH FLOW ANALYSIS
The following subsections of "Results of Operations and Historical Cash Flow Analysis" provide a discussion on
the changes in various line items presented on the Consolidated Statements of Income as well as a discussion of
the changes on the Consolidated Statements of Cash Flows.
Results of Operations
Earnings from Continuing Operations
SCE's earnings from continuing operations were $260 million and $604 million for the three and nine months ended
September 30, 2004, respectively, compared with $331 million and $659 million for the three and nine months ended
September 30, 2003, respectively. The decrease in third quarter earnings primarily reflects a $79 million
reduction in regulatory items. After adjusting for regulatory items, higher revenue authorized in the utility's
2003 GRC for 2004 more than offset the expiration of the
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incentive mechanism for the San Onofre nuclear plant and higher operating and maintenance expense. SCE's 2004
third quarter earnings included two positive regulatory items totaling $64 million resulting from the
implementation of the 2003 GRC decision that were partially offset by $14 million for the anticipated refund of
employee safety awards previously recognized. Positive regulatory items that occurred in the third quarter of
2003 included $79 million related to the CPUC decision on cost allocation and $50 million for the disposition of
the PROACT account. The decrease for the nine months ended September 30, 2004, compared with the year-earlier
period, primarily reflects the expiration of the incentive mechanism for San Onofre and the net effect of several
regulatory items partially offset by higher authorized revenue. SCE's 2004 earnings include $157 million (after
tax) from regulatory items primarily related to its 2003 GRC decision. SCE's 2003 earnings include $189 million
(after tax) from various positive regulatory items.
Operating Revenue
SCE's retail sales represented approximately 88% and 86% of operating revenue for the three- and nine-month
periods ended September 30, 2004, respectively, and approximately 93% for both the three- and nine-month periods
ended September 30, 2003, respectively. Due to warmer weather during the summer months, operating revenue during
the third quarter of each year is significantly higher than other quarters.
Operating revenue decreased for both the three- and nine-month periods ended September 30, 2004, compared to the
same periods in 2003. The decreases were mainly due to the implementation of a CPUC-approved customer rate
reduction plan effective August 1, 2003, a decrease in sales volume resulting from the CDWR providing a greater
amount of energy to SCE's customers in 2004, as compared to 2003 (see discussion below) and the recognition of
revenue in 2003 from a CPUC-authorized surcharge collected in 2002 used to recover costs incurred in 2003. There
was no surcharge revenue recognized in 2004. The three- and nine-month period decreases were partially offset by
the recognition of revenue resulting from the consolidation of SCE's variable interest entities on March 31, 2004
(see "Critical Accounting Policies" and "New Accounting Principles"), higher resale sales revenue due to a
greater amount of excess energy in 2004, as compared to 2003. As a result of the CDWR contracts allocated to
SCE, excess energy from SCE sources may exist at certain times, which then is resold in the energy markets. In
addition, the decreases were partially offset by regulatory adjustments resulting from the implementation of the
2003 GRC decision (see "Regulatory Matters--Transmission and Distribution--2003 General Rate Case Proceeding" for
further discussion). The nine-month period decrease was also partially offset by an allocation adjustment for
the CDWR energy purchases recorded in 2003.
Amounts SCE bills and collects from its customers for electric power purchased and sold by the CDWR to SCE's
customers (beginning January 17, 2001), CDWR bond-related costs (beginning November 15, 2002) and direct access
exit fees (beginning January 1, 2003) are remitted to the CDWR and are not recognized as revenue by SCE. These
amounts were $693 million and $1.9 billion for the three- and nine-month periods ended September 30, 2004,
compared to $541 million and $1.4 billion for the same periods in 2003.
Operating Expenses
Fuel expense increased in both the three- and nine-month periods ended September 30, 2004, as compared to the
same periods in 2003, primarily due to the consolidation of SCE's variable interest entities. The nine-month
period increase also reflects increased coal expense at SCE's Mohave coal facility due increased generation in
the second quarter of 2004, as compared to the same period in 2003, resulting from a planned outage and
maintenance repairs in the second quarter of 2003, offset by lower coal expense during the first quarter of 2004
at SCE resulting from a scheduled major overhaul at SCE's Four Corners coal facility in 2004.
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Purchased-power expense decreased in both the three- and nine-month periods ended September 30, 2004, as compared
to the same periods in 2003. The decrease was mainly due to the consolidation of SCE's variable interest
entities The decrease was partially offset by an increase in ISO-related costs, higher expenses related to power
purchased by SCE from qualifying facilities (QFs), as discussed below, higher expenses resulting from an increase
in the number of gas bilateral contracts in 2004, as compared to 2003, and higher unrealized losses associated
with hedging instruments in 2004, as compared to 2003. The nine-month period increase was also partially offset
by the receipt of a settlement agreement payment between SCE and El Paso Natural Gas Company (see "Regulatory
Matters--Transmission and Distribution--Wholesale Electricity and Natural Gas Markets").
Federal law and CPUC orders required SCE to enter into contracts to purchase power from QFs at CPUC-mandated
prices. Energy payments to gas-fired QFs are generally tied to spot natural gas prices. Effective May 2002,
energy payments for most renewable QFs were converted to a fixed price of 5.37(cent)-per-kWh. Average spot natural
gas prices were higher during the three- and nine-month periods ended September 30, 2004, compared to the same
periods in 2003.
Provisions for regulatory adjustment clauses - net decreased in both the three- and nine-month periods ended
September 30, 2004, mainly due to the collection of the PROACT balance and the implementation of the
CPUC-authorized rate-reduction plan in the summer of 2003. This resulted in decreases of approximately
$425 million and $735 million for the three- and nine-month periods, respectively. The decreases also reflect a
net effect of approximately $40 million and $220 million of regulatory adjustments, for the three- and nine-month
periods, respectively, related to the implementation of SCE's 2003 GRC decision (see "Regulatory
Matters--Transmission and Distribution--2003 General Rate Case Proceeding") and the deferral of costs for future
recovery in the amount of approximately $34 million and $102 million associated with the bark beetle infestation
for the three- and nine-month periods ended September 30, 2004, respectively (see "Regulatory Matters--Other
Regulatory Matters--Catastrophic Event Memorandum Account"). The decreases also reflect the mark-to-market of
hedging instruments, including the recovery of approximately $115 million (for the nine months ended
September 30, 2004) of gas hedging costs through regulatory mechanisms in the first quarter of 2003. The
decreases were partially offset by the favorable resolution of certain regulatory cases recorded in the third
quarter of 2003 and the anticipated refund of employee injury and illness performance incentive rewards
previously earned (see "Regulatory Matters--Other Regulatory Matters--Investigations Regarding Performance
Incentive Rewards"). The nine-month period decrease was also partially offset by the El Paso settlement payment
received, of which $66 million was refunded to customers through the ERRA account, as well as an allocation
adjustment of approximately $110 million for CDWR energy purchases recorded in 2003.
Other operation and maintenance expense increased in both the three- and nine-month periods ended September 30,
2004, compared to the same periods in 2003, mainly due to costs incurred in 2004 related to the removal of trees
and vegetation associated with the bark beetle infestation (see "Regulatory Matters--Other Regulatory
Matters--Catastrophic Event Memorandum Account"), higher operation and maintenance costs related to the San Onofre
Unit 2 refueling outage in 2004, and operating and maintenance expense related to the consolidation of SCE's
variable interest entities. These increases were partially offset by a decrease in postretirement benefits other
than pensions, including the effects of adopting the Medicare Prescription Drug, Improvement and Modernization
Act of 2003 in the third quarter of 2004 (see "New Accounting Principles" for further discussion) and lower
worker's compensation claims in 2004. The nine-month increase was also due to higher operation and maintenance
costs related to a scheduled major overhaul at SCE's Four Corners coal facility and additional costs for 2003
incentive compensation due to upward revisions in the computation in 2004.
Depreciation, decommissioning and amortization expense decreased in the three-month period ended September 30,
2004, and increased in the nine-month period ended September 30, 2004, as compared to the same periods in 2003.
The three- and nine-month variances were mainly due to the impact of the
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expiration of the Palo Verde and San Onofre ICIP mechanisms in 2004, an increase in SCE's depreciation expense
associated with additions to transmission and distribution assets, and the consolidation of SCE's variable
interest entities. Contributing to the nine-month increase was an increase in SCE's nuclear decommissioning
expense.
Other Income and Deductions
Interest and dividend income decreased in both the three- and nine-month periods ended September 30, 2004, as
compared to the same periods in 2003, due to the absence of interest income on the PROACT balance in 2004, as
compared to 2003. At July 31, 2003 the PROACT balance was overcollected, and was transferred to the ERRA on
August 1, 2003.
Other nonoperating income decreased for the three-month period ended September 30, 2004 mainly due to SCE's
recognition of 2000 performance rewards related to Palo Verde approved by the CPUC and recorded in the third
quarter of 2003.
Minority interest represents SCE's variable interest entities consolidated upon adoption of a new accounting
pronouncement in second quarter 2004 (see "Critical Accounting Policies" and "New Accounting Principles").
Income Taxes
Income taxes decreased for both the three- and nine-month periods ended September 30, 2004, compared to the same
periods in 2003, primarily due to a decrease in pre-tax income as well as changes in property related
flow-through taxes between the periods and resumption of the dividend payment to the employee stock ownership
plan in 2004. The decreases were partially offset by a reduction in 2003 tax expense related the flow-through
impact of the sale of SCE's fuel oil pipeline and storage business. The nine-month decrease was also partially
offset by the 2003 favorable resolution of a FERC rate case.
SCE's composite federal and state statutory rate was 40.2% and 39.7% for the three- and nine-month periods ended
September 30, 2004 which approximates its composite federal and state statutory rate of 40%.
Earnings from Discontinued Operations
Earnings from discontinued operations were $44 million and $50 million for the three and nine months ended
September 30, 2003, respectively, reflecting SCE's oil storage and pipeline facilities that were sold in third
quarter 2003. SCE recorded an after-tax gain on sale of $44 million for these facilities.
Historical Cash Flow Analysis
The "Historical Cash Flow Analysis" section of this MD&A discusses consolidated cash flows from operating,
financing and investing activities.
Cash Flows from Operating Activities
Net cash provided by operating activities was $1.7 billion for the nine months ended September 30, 2004, and $2.3
billion for the comparable period in 2003. The change in cash provided by operating activities was mainly due to
overcollections in 2003 used to recover PROACT, as well as the timing of cash receipts and disbursements related
to working capital items.
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Cash Flows from Financing Activities
Net cash used by financing activities was $175 million for the nine months ended September 30, 2004, compared to
net cash used by financing activities of $931 million for the comparable period in 2004. Cash used by financing
activities from continuing operations in 2004 mainly consisted of long-term and short-term debt payments.
SCE financing activities include the issuance of $300 million of 5% bonds due in 2014, $525 million of 6% bonds
due in 2034 and $150 million of floating rate bonds due in 2006 during the first quarter of 2004. The proceeds
from these issuances were used to redeem $300 million of 7.25% first and refunding mortgage bonds due March 2026,
$225 million of 7.125% first and refunding mortgage bonds due July 2025, $200 million of 6.9% first and refunding
mortgage bonds due October 2018, and $100 million of junior subordinated deferrable interest debentures due June
2044. In addition, during the first quarter of 2004, SCE paid the $200 million outstanding balance of its credit
facility, as well as remarketed approximately $550 million of pollution-control bonds with varying maturity dates
ranging from 2008 to 2040. Approximately $354 million of these pollution-control bonds had been held by SCE
since 2001 and the remaining $196 million were purchased and reoffered in 2004. In March 2004, SCE issued
$300 million of 4.65% first and refunding mortgage bonds due in 2015 and $350 million of 5.75% first and refunding
mortgage bonds due in 2035. A portion of the proceeds from the March 2004 first and refunding mortgage bond
issuances were used to fund the acquisition and construction of the Mountainview project. During the third
quarter, SCE paid $125 million of 5.875% bonds due in September 2004. Financing activities in 2004 also included
dividend payments of $595 million of equity to Edison International.
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% first and
refunding mortgage bonds.
Cash Flows from Investing Activities
Net cash used by investing activities was $1.5 billion for the nine months ended September 30, 2004, compared to
$678 million for the comparable period in 2003. Cash flows from investing activities are affected by additions
to property and plant and funding of nuclear decommissioning trusts.
Investing activities in 2004 reflect $1.1 billion in additions to property and plant, primarily for transmission
and distribution asset, and $285 million of acquisition costs related to the Mountainview project. Investing
activities in 2003 reflect $820 million in additions to property and plant, primarily for transmission and
distribution assets.
ACQUISITION
On March 12, 2004, SCE acquired Mountainview Power Company LLC, which owns a power plant under construction in
Redlands, California. SCE has recommenced full construction of the approximately $600 million project, which is
expected to be completed in early 2006. The construction work in progress for this project is recorded in
nonutility property on Edison International's September 30, 2004 balance sheet. SCE expects to finance the
capital costs of the project with debt and equity consistent with its authorized capital structure.
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CRITICAL ACCOUNTING POLICIES
Variable Interest Entities
A new accounting standard provides guidance on the identification of, and financial reporting for, variable
interest entities (VIEs), where control may be achieved through means other than voting rights. An enterprise
that is expected to absorb or receive the majority of a VIE's expected losses or residual returns, or both, must
consolidate the VIE, unless specific exceptions apply. See "New Accounting Principles."
SCE analyzes its potential variable interests by calculating operating cash flows. A fixed-price contract to
purchase electricity from a power plant does not transfer sufficient risk to the purchaser to be considered a
variable interest. A contract with a non-natural-gas-fired plant that is based on the price of natural gas is
also not a variable interest. A contract of short duration with respect to the economic life of the project is
not considered to be a significant variable interest.
SCE has 272 long-term power-purchase contracts with independent power producers that own QFs. SCE was required
under federal law to sign such contracts, which typically require SCE to purchase 100% of the power produced by
these facilities under terms and pricing controlled by the CPUC. SCE conducted a review of its QF contracts and
determined that SCE has variable interests in 17 contracts with gas-fired cogeneration plants that are potential
VIEs and that contain variable pricing provisions based on the prices of natural gas and for which SCE does not
have sufficient information to determine if the projects qualify for a scope exception. SCE requested from the
entities that hold these contracts the financial information necessary to determine whether SCE must consolidate
these projects. All 17 entities declined to provide SCE with the necessary financial information. However, four
of the 17 contracts are with entities 49%-50% owned by a related party, Edison Mission Energy (EME). Although
the four related-party entities have declined to provide their financial information to SCE, Edison International
has access to such information and has provided combined financial statements to SCE. SCE has determined that it
must consolidate the four power projects partially owned by EME based on a qualitative analysis of the facts and
circumstances of the entities, including the related-party nature of the transaction. SCE will continue to
attempt to obtain information for the other 13 projects in order to determine whether they should be consolidated
by SCE. The remaining 255 contracts will not be consolidated by SCE under the new accounting standard since SCE
lacks a variable interest in these contracts or the contracts are with governmental agencies, which are generally
excluded from the standard.
See the year-ended 2003 MD&A for a complete discussion of Edison International's other critical accounting
policies.
NEW ACCOUNTING PRINCIPLES
In May 2004, the Financial Accounting Standards Board issued accounting guidance related to the Medicare
Prescription Drug, Improvement and Modernization Act of 2003. SCE adopted this guidance effective July 1, 2004,
which resulted in a decrease of $81 million to SCE's accumulated benefit obligation for postretirement benefits
other than pensions. SCE's third quarter 2004 expense decreased approximately $5 million as a result of the
subsidy. According to proposed federal regulations, SCE's retiree health care plans provide prescription drug
benefits that are deemed to be actuarially equivalent to Medicare benefits. Accordingly, SCE recognized the
subsidy in the measurement of its accumulated obligation and recorded an actuarial gain.
In December 2003, the Financial Accounting Standards Board issued a revision to an accounting Interpretation
(originally issued in January 2003), Consolidation of Variable Interest Entities. The primary objective of the
Interpretation is to provide guidance on the identification of, and financial
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reporting for, VIEs, where control may be achieved through means other than voting rights. Under the
Interpretation, the enterprise that is expected to absorb or receive the majority of a VIE's expected losses or
residual returns, or both, must consolidate the VIE, unless specific exceptions apply. This Interpretation is
effective for special purpose entities, as defined by accounting principles generally accepted in the United
States, as of December 31, 2003, and all other entities as of March 31, 2004. On March 31, 2004, SCE
consolidated four power projects partially owned by EME. See "Critical Accounting Policies--Variable Interest
Entities" for further discussion.
COMMITMENTS AND GUARANTEES
The following is an update to SCE's commitments and guarantees. See the "Commitments and Guarantees" section of
the year-ended 2003 MD&A for a detailed discussion of commitments and guarantees.
SCE's long-term debt maturities and sinking-fund requirements for the five twelve-month periods following
September 30, 2004 are: 2005 - $247 million; 2006 - $928 million; 2007 - $1.2 billion; 2008 - $122 million; 2009
- $219 million; and thereafter - $2.7 billion. These amounts have been updated to reflect financing activities
during the nine months ended September 30, 2004.
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Item 3. Quantitative and Qualitative Disclosures About Market Risk
Information responding to Part I, Item 3 is included in Part I, Item 2, "Management's Discussion and Analysis of
Financial Condition and Results of Operations" under the heading "Market Risk Exposures" and is incorporated
herein by this 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) or 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 that evaluation, the Chief Executive Officer and Chief Financial
Officer have concluded that, as of the end of the period, SCE's disclosure controls and procedures are effective.
Internal Control Over Financial Reporting
There were no changes in SCE's internal control over financial reporting (as such term is defined in Rules
13a-15(f) or 15d-15(f) under the Exchange Act) during the quarter to which this report relates that have
materially affected, or are reasonably likely to materially affect, SCE's internal control over financial
reporting.
For the reasons discussed in Note 1 of the Notes to Consolidated Financial Statements, SCE has not designed,
established, or maintained internal control over financial reporting for four variable interest entities,
referred to as "VIEs," that SCE was required to consolidate under an accounting interpretation issued by the
Financial Accounting Standards Board. SCE's evaluation of internal control over financial reporting did not
include these VIEs.
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PART II OTHER INFORMATION
Item 1. Legal Proceedings
Navajo Nation Litigation
Information about the Navajo Nation Litigation appears in Part I, Item 2, "Management's Discussion and Analysis
of Financial Condition and Results of Operations" under the heading "Other Developments--Navajo Nation Litigation"
and is incorporated herein by this reference. Information about the Navajo Nation Litigation was previously
reported in Part I, Item 3 of SCE's Annual Report on Form 10-K for the year ended December 31, 2003, and in
Part II, Item 1 of SCE's Quarterly Report on Form 10-Q for the period ending March 31, 2004, and in Part II,
Item 1 of SCE's Quarterly Report on Form 10-Q for the period ending June 30, 2004.
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Item 6. Exhibits
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
effective May 20, 2004 (File No. 1-2313, SCE Form 8-K, dated May 21, 2004)*
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.
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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 8, 2004
