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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 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 August 4, 2004
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Common Stock, no par value 434,888,104
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SOUTHERN CALIFORNIA EDISON COMPANY
INDEX
Page
No.
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Part I. Financial Information:
Item 1. Financial Statements:
Consolidated Statements of Income - Three and Six Months
Ended June 30, 2004 and 2003 1
Consolidated Statements of Comprehensive Income -
Three and Six Months Ended June 30, 2004 and 2003 1
Consolidated Balance Sheets - June 30, 2004
and December 31, 2003 2
Consolidated Statements of Cash Flows -
Six Months Ended June 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 21
Item 3. Quantitative and Qualitative Disclosures About Market Risk 41
Item 4. Controls and Procedures 41
Part II. Other Information:
Item 1. Legal Proceedings 42
Item 4. Submission of Matters to a Vote of Security Holders 43
Item 6. Exhibits and Reports on Form 8-K 44
Signatures
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SOUTHERN CALIFORNIA EDISON COMPANY
PART I FINANCIAL INFORMATION
Item 1. Financial Statements
CONSOLIDATED STATEMENTS OF INCOME
Three Months Ended Six Months Ended
June 30, June 30,
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In millions 2004 2003 2004 2003
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(Unaudited)
Operating revenue $ 2,176 $ 2,386 $ 3,872 $ 4,200
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Fuel 248 49 296 107
Purchased power 527 722 1,107 1,174
Provisions for regulatory adjustment clauses - net (33) 505 (51) 809
Other operation and maintenance 574 474 1,149 957
Depreciation, decommissioning and amortization 222 177 439 389
Property and other taxes 46 42 91 82
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Total operating expenses 1,584 1,969 3,031 3,518
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Operating income 592 417 841 682
Interest and dividend income 4 40 9 79
Other nonoperating income 11 21 44 30
Interest expense - net of amounts capitalized (104) (114) (209) (239)
Other nonoperating deductions (20) (8) (33) (16)
Minority interest (85) -- (85) --
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Income from continuing operations before tax 398 356 567 536
Income tax 155 130 223 208
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Income from continuing operations 243 226 344 328
Income from discontinued operations - net of tax -- 3 -- 6
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Net income 243 229 344 334
Dividends on preferred stock
subject to mandatory redemption -- 3 -- 4
Dividends on preferred stock
not subject to mandatory redemption 1 1 3 3
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Net income available for common stock $ 242 $ 225 $ 341 $ 327
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
Three Months Ended Six Months Ended
June 30, June 30,
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In millions 2004 2003 2004 2003
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(Unaudited)
Net income $ 243 $ 229 $ 344 $ 334
Other comprehensive income, net of tax:
Amortization of cash flow hedges 1 1 2 1
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Comprehensive income $ 244 $ 230 $ 346 $ 335
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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
June 30, December 31,
In millions 2004 2003
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(Unaudited)
ASSETS
Cash and equivalents $ 401 $ 95
Restricted cash 67 66
Receivables, less allowances of $33 and $30
for uncollectible accounts at respective dates 812 751
Accrued unbilled revenue 555 408
Fuel inventory 7 10
Materials and supplies, at average cost 195 168
Accumulated deferred income taxes - net 300 563
Prepayments and other current assets 96 58
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Total current assets 2,433 2,119
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Nonutility property - less accumulated provision
for depreciation of $29 and $24 at respective dates 458 116
Property of variable interest entities - net 393 --
Nuclear decommissioning trusts 2,581 2,530
Other investments 144 153
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Total investments and other assets 3,576 2,799
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Utility plant, at original cost:
Transmission and distribution 15,183 14,861
Generation 1,360 1,371
Accumulated provision for depreciation (4,507) (4,386)
Construction work in progress 734 600
Nuclear fuel, at amortized cost 143 141
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Total utility plant 12,913 12,587
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Regulatory assets - net 369 510
Other deferred charges 519 506
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Total deferred charges 888 1,016
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Total assets $ 19,810 $ 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
June 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 372 371
Preferred stock to be redeemed within one year 9 9
Accounts payable 1,088 891
Accrued taxes 547 475
Regulatory liabilities - net 256 361
Other current liabilities 1,095 1,308
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Total current liabilities 3,367 3,615
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Long-term debt 5,193 4,121
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Accumulated deferred income taxes - net 2,698 2,726
Accumulated deferred investment tax credits 131 136
Customer advances and other deferred credits 491 429
Power-purchase contracts 186 213
Preferred stock subject to mandatory redemption 139 141
Accumulated provision for pensions and benefits 379 330
Asset retirement obligations 2,131 2,084
Other long-term liabilities 254 242
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Total deferred credits and other liabilities 6,409 6,301
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Total liabilities 14,969 14,037
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Commitments and contingencies (Notes 2 and 4)
Minority interest 455 --
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Common stock (434,888,104 shares outstanding at each date) 2,168 2,168
Additional paid-in capital 345 338
Accumulated other comprehensive loss (17) (19)
Retained earnings 1,761 1,868
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Total common shareholder's equity 4,257 4,355
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Preferred stock not subject to mandatory redemption 129 129
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Total shareholders' equity 4,386 4,484
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Total liabilities and shareholders' equity $ 19,810 $ 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
Six Months Ended
June 30,
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In millions 2004 2003
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(Unaudited)
Cash flows from operating activities:
Income from continuing operations $ 344 $ 328
Adjustments to reconcile to
net cash provided by operating activities:
Depreciation, decommissioning and amortization 439 389
Other amortization 46 50
Minority interest 85 --
Deferred income taxes and investment tax credits 163 (28)
Regulatory assets - long-term - net 152 147
Gas options (13) 2
Other assets (3) 34
Other liabilities 57 (152)
Changes in working capital net of effects from
consolidation of variable interest entities:
Receivables and accrued unbilled revenue (157) (155)
Regulatory liabilities - short-term - net (105) 579
Fuel inventory, materials and supplies 7 (5)
Prepayments and other current assets (36) (83)
Accrued interest and taxes 97 151
Accounts payable and other current liabilities (95) 143
Operating cash flows from discontinued operations -- 8
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Net cash provided by operating activities 981 1,408
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Cash flows from financing activities:
Long-term debt issued 1,598 (11)
Long-term debt repaid (842) (729)
Bonds remarketed - net 350 --
Redemption of preferred stock (2) (5)
Rate reduction notes repaid (115) (115)
Short-term debt financing - net (200) --
Cash dividends to minority interest (49) --
Dividends paid (448) (8)
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Net cash provided (used) by financing activities 292 (868)
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Cash flows from investing activities:
Additions to property and plant (721) (540)
Acquisition costs related to nonutility generation plant (285) --
Contributions to nuclear decommissioning trusts - net (42) (1)
Sales of investments in other assets 2 3
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Net cash used by investing activities (1,046) (538)
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Effect of consolidation of variable interest entities on cash 79 --
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Net increase in cash and equivalents 306 2
Cash and equivalents, beginning of period 95 992
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Cash and equivalents, end of period, continuing operations $ 401 $ 994
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The accompanying notes are an integral part of these financial statements.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Management's Statement
In the opinion of management, all adjustments, including recurring accruals, have been made that are necessary for a fair
presentation of the financial position, results of operations and cash flows in accordance with accounting principles generally
accepted in the United States for the periods covered by this report. The results of operations for the period ended June 30, 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).
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 June 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 its 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 June 30, 2004, SCE's 13-month weighted-average common equity component of total capitalization was 53%. At June 30,
2004, SCE had the capacity to pay $462 million in additional dividends and continue to maintain its CPUC-authorized capital structure
based on the 13-month weighted-average method. Based on recorded June 30, 2004 balances, SCE's common equity to total capitalization
ratio, for ratemaking purposes, was 48%. SCE had the capacity to pay $28 million of additional dividends based on June 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 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
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 273 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 22 contracts with gas-fired cogeneration plants that contain variable pricing provisions based on the price of
natural gas. SCE requested from the entities that hold these contracts the financial information necessary to determine whether SCE
must consolidate these projects. All 22 entities declined to provide SCE with the necessary financial information. However, four of
the 22 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 18 projects in order to determine whether they should be consolidated by SCE.
The remaining 251 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. Additionally, SCE has six five-year power contracts with non-QF
generators. These contracts are not considered to be significant variable interests due to their short duration.
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 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
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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.
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.
Three Months Ended Six Months Ended
June 30, June 30,
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In millions 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Net income available for common stock, as reported $ 242 $ 225 $ 341 $ 327
Add: stock-based compensation expense using
the intrinsic value accounting method - net of tax 2 1 4 2
Less: stock-based compensation expense using
the fair-value accounting method - net of tax 2 1 4 3
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Pro forma net income available for common stock $ 242 $ 225 $ 341 $ 326
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Supplemental Cash Flows Information
Six Months Ended
June 30,
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In millions 2004 2003
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(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 June 30, 2004 is $393 million ($896 million at original cost less $503
million in accumulated depreciation).
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
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 and Six Months Ended
June 30,
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In millions 2004
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(Unaudited)
Operating revenue $ 94
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Fuel 188
Purchased power (208)
Other operation and maintenance 20
Depreciation, decommissioning and amortization 9
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Total operating expenses 9
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Operating income 85
Minority interest (85)
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Income from continuing operations before tax $ --
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As noted under New Accounting Principles, SCE also has 18 other contracts with certain qualifying facilities that contain variable
pricing provisions based on the price of natural gas. 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 18 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 471 MW. SCE paid $69 million and $118
million, respectively, for the three and six months ended June 30, 2004 and $61 million and $115 million, respectively, for the three
and six months ended June 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.
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 (TURN), a consumer
Page 9
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
advocacy group, and other parties appealed to 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 issued its opinion affirming the
federal district court on all claims, with the exception of the challenges founded upon California state law, which the Ninth Circuit
referred to the California Supreme Court.
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. The matter was returned to the Ninth Circuit for final disposition, and in December
2003, the Ninth Circuit unanimously affirmed the original stipulated judgment of the federal district court. In January 2004, the
Ninth Circuit 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 CPUC 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.
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 Nuclear Generating Station incremental cost incentive pricing 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. As a result of the
implementation of the 2003 GRC decision, SCE recorded pre-tax net regulatory adjustments of $180 million as a credit to provision for
regulatory adjustment clauses during the second quarter of 2004.
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. This will result in an
approximate $55 million pre-tax gain in the third quarter of 2004. In addition, SCE expects to record approximately
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
$48 million in pre-tax gains related to the rate recovery of 1997-1998 generation-related capital additions and the related revenue
requirement in the third quarter of 2004, as a further result of the implementation of the 2003 GRC decision.
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. SCE has proposed that the GRC rate increase be combined with other rate changes from pending rate
proceedings and be 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.
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. Pacific Gas and Electric (PG&E) and San Diego Gas & Electric (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 did not file a challenge to the decision as to the first priority issue, so the first priority
requirement is now final. The California Supreme Court
Page 11
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
has 60 days (extendable to 90 days) within which to accept or reject the petition for review as to the jurisdiction issue.
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, 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. The uncertainty over a post-2005 coal and water supply has prevented SCE and other Mohave co-owners from making
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.
Negotiations are continuing among the relevant parties in an effort to resolve the coal and water supply issues, but no resolution
has been reached. 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) 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, 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 approximately three years is likely. Evidentiary hearings took place in June and July of 2004, and a decision on this
matter is not expected before November 2004. 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 an 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 (PX)/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, 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.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 any
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. Additional settlement payments
totaling approximately $134 million are due from El Paso over a 20-year period. In addition, 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 approximately $37 million in 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 April 26, 2004
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 that is expected to exceed $40 million. The Duke settlement remains
subject to the approval of the FERC and the CPUC. Additionally, 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.
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 June 30, 2004, $6 million in contributions have
been made. SCE anticipates that its original expectation will be met by year-end 2004.
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Expense components are:
Three Months Ended Six Months Ended
June 30, June 30,
- --------------------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
- --------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 22 $ 19 $ 44 $ 39
Interest cost 41 41 82 81
Expected return on plan assets (58) (46) (115) (93)
Net amortization and deferral 6 8 11 17
- --------------------------------------------------------------------------------------------------------------------------------
Expense under accounting standards 11 22 22 44
Regulatory adjustment - deferred -- (11) -- (22)
- --------------------------------------------------------------------------------------------------------------------------------
Total expense recognized $ 11 $ 11 $ 22 $ 22
- --------------------------------------------------------------------------------------------------------------------------------
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 June 30,
2004, $12 million in contributions have been made. SCE anticipates that its original expectation will be met by year-end 2004.
In May 2004, the Financial Accounting Standards Board issued accounting guidance related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003. SCE will adopt this guidance in third quarter 2004. If SCE's retiree health care plans
provide prescription drug benefits that are deemed to be actuarially equivalent to Medicare benefits, SCE will recognize the subsidy
in the measurement of its accumulated obligation and record an actuarial gain. Proposed federal regulations defining actuarial
equivalency are expected in third quarter 2004, with final regulations expected to be released by year-end 2004. Until the proposed
regulations are issued, SCE is unable to predict the effect of the new law on its postretirement health care costs and obligations.
Expense components are:
Three Months Ended Six Months Ended
June 30, June 30,
- -------------------------------------------------------------------------------------------------------------------------------
In millions 2004 2003 2004 2003
- -------------------------------------------------------------------------------------------------------------------------------
(Unaudited)
Service cost $ 11 $ 11 $ 22 $ 21
Interest cost 32 30 65 61
Expected return on plan assets (27) (22) (55) (44)
Net amortization and deferral 8 10 16 20
- -------------------------------------------------------------------------------------------------------------------------------
Total expense $ 24 $ 29 $ 48 $ 58
- -------------------------------------------------------------------------------------------------------------------------------
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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SOUTHERN CALIFORNIA EDISON COMPANY
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
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 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. 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 26 identified sites is $88 million. In third quarter 2003, SCE sold
certain oil storage and pipeline facilities. This sale caused a reduction in SCE's recorded estimated minimum environmental
liability. The ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties
inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified
sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of
identifying additional sites; and the time periods over which site remediation is expected to occur. SCE believes that, due to these
uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $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
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
expects to recover costs incurred at its remaining sites through customer rates. SCE has recorded a regulatory asset of $63 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 June 30, 2004 were $16 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 this matter 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 service reliability, customer satisfaction, and employee safety. SCE
received two letters over the last year 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
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
satisfaction rewards of $28 million for the years 1998, 1999 and 2000. Potential customer satisfaction rewards aggregating
$10 million for 2001 and 2002 are pending before the CPUC and have not been recognized in income by SCE. SCE also had 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 widespread misconduct, SCE
proposed to refund to ratepayers all of the $12 million in PBR rewards that may be attributed 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 about $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 with respect to the customer satisfaction survey misconduct by severing the employment of several
supervisory personnel, updating system processes and related documentation for survey reporting, and implementing additional
supervisory controls over data collection and processing.
As mentioned above, SCE is also eligible under its CPUC-approved PBR mechanism to earn rewards or penalties based on its performance
in comparison to CPUC-approved standards of service reliability and employee safety. In light of the problems uncovered with the
customer satisfaction surveys, SCE commenced investigations into the accuracy and completeness of SCE's service reliability and
employee safety reporting. While the safety and service reliability investigations are not yet complete, SCE has preliminarily
concluded that some of its data collection procedures for recording employee injuries may have been inadequate and some misreporting
may have occurred. SCE has not reached any conclusions as to the effect of those problems on the validity of safety incentive
performance payments. SCE has advised the CPUC staff of the existence of the safety and reliability investigations, promised to
provide copies of the investigative reports, and committed to return to ratepayers or forgo any PBR rewards that were earned based on
data shown to be inaccurate. Both the safety and the service reliability investigations are being pursued aggressively and will be
completed as soon as possible. Since the inception of PBR payments in 1997, SCE has received $20 million in employee safety
incentive performance payments and, based on SCE's records, may be entitled to an additional $15 million. As for service
reliability, since the inception of PBR payments in 1997, SCE has received $8 million in rewards based on frequency of outage data
and has applied for an additional $5 million award based on frequency of outage data for 2001.
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, service reliability and/or employee safety. The CPUC also may consider whether to
impose additional penalties on SCE.
Page 17
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SCE cannot predict with certainty the outcome of these matters or estimate the potential amount of refunds, disallowances and
penalties that may be required.
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 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 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 District Court subsequently issued a scheduling order that imposes a December 31, 2004
discovery cut-off and sets a status conference for January 21, 2005. No trial date was established in the scheduling order. The
parties to the D.C. District Court action are currently engaged in scheduling and completing the remaining discovery in the case.
The Federal Circuit Court of Appeals, 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 Court of Appeals decision. Both petitions were denied on March 9, 2004. On March 16, 2004, the Court of
Appeals issued an order remanding the case against the Government to the Federal Court of 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 in the remanded Court of Federal Claims
case as a party 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.
Page 18
SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Nuclear Insurance
Federal law limits public liability claims from a nuclear incident to $10.8 billion. SCE and other owners of the San Onofre and Palo
Verde Nuclear Generating Stations have purchased the maximum private primary insurance available ($300 million). The balance is
covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear
incident at any licensed reactor in the 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 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 has the obligation to begin acceptance of
spent nuclear fuel not later than January 31, 1998. However, the DOE did not meet its obligation. It is not certain when the DOE
will begin accepting spent nuclear fuel from San Onofre or other nuclear power plants. Extended delays by the DOE have led to the
construction of costly alternatives, including 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.
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 1, 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 is scheduled to be
completed by late 2004 and from the Unit 2 spent fuel pool to the independent spent fuel storage
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SOUTHERN CALIFORNIA EDISON COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
installation 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 early 2006.
In order to increase on-site storage capacity and maintain core off-load capability, Palo Verde has constructed a dry cask storage
facility. Arizona Public Service, 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 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 June 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 six months ended June 30, 2003.
For the three months and six months ended June 30, 2003, revenue from discontinued operations was $8 million and $18 million,
respectively, and pre-tax income was $4 million and $10 million, respectively.
Page 20
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 six-month
periods ended June 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 six-month periods ended June 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 DEVELOPMENT
2003 General Rate Case Proceeding
On July 8, 2004, the CPUC issued a final decision on SCE's 2003 General Rate Case (GRC) application, authorizing an annual increase
of approximately $73 million in base rates. As a result of the implementation of the 2003 GRC decision, SCE recorded pre-tax net
regulatory adjustments of $180 million during the second quarter of 2004. 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. This will
result in an approximate $55 million pre-tax gain in the third quarter of 2004. In addition, SCE expects to record approximately $48
million in pre-tax gains related to the rate recovery of 1997-1998 generation-related capital additions and the related revenue
requirement in the third quarter of 2004, as a further result of the implementation of the 2003 GRC decision. See "Regulatory
Matters--Transmission and Distribution--2003 General Rate Case Proceeding" for further details.
Page 21
LIQUIDITY ISSUES
SCE's liquidity is primarily affected by under- or over-collections of procurement-related costs and access to capital markets or
external financings. At June 30, 2004, SCE's credit and long-term issuer ratings from Standard & Poor's and Moody's Investors
Service were BBB and Baa3, respectively. On March 22, 2004, Moody's Investors Service placed SCE's credit rating under review for
possible upgrade.
At June 30, 2004, SCE had cash and equivalents of $401 million and long-term debt, including current maturities, of $5.6 billion.
SCE has a $700 million credit facility that expires in December 2006. As of June 30, 2004, the credit facility was not utilized,
except for $2 million supporting letters of credit. SCE's 2004 estimated cash outflows consist of:
o $125 million of 5.875% bonds due 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;
o Fuel and procurement-related costs; and
o General operating expenses.
SCE expects to meet its continuing obligations and cash outflows for 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.
On March 30, 2004, SCE transferred, through a dividend to Edison International, $300 million of common equity. The purpose of this
dividend was to continue to rebalance SCE's capital structure in accordance with CPUC requirements. On May 21, 2004, SCE paid a $145
million dividend to Edison International.
The CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International. In its 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 June 30, 2004, SCE's 13-month
weighted-average common equity component of total capitalization was 53%. At June 30, 2004, SCE had the capacity to pay $462 million
in additional dividends and continue to maintain its CPUC-authorized capital structure based on the 13-month weighted-average
method. Based on recorded June 30, 2004 balances, SCE's common equity to total capitalization ratio, for rate-making purposes, was
48%. SCE had the capacity to pay $28 million of additional dividends based on June 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
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$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, of which approximately
$196 million of these pollution-control bonds were reoffered. 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.
As of June 30, 2004, SCE posted approximately $24 million ($22 million in cash and $2 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'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. However, 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 is currently considering a bill that is intended to create a durable regulatory framework to stimulate
investment in generation resources. The latest publicly available version of Assembly Bill 2006, which is entitled the "Reliable
Electric Service Act," proposes to affirm the obligation of utilities to plan and provide adequate, efficient, and cost-effective
supply and demand resources and requires utilities to prepare a long-term resource plan to achieve a diversified portfolio of
cost-effective supply and demand resources. The proposed bill also states that the CPUC must establish and maintain rates that
ensure the full recovery of reasonable investments made by utilities, and the full cost of contracting for nonutility generation.
Because the bill continues to be debated and amended in the California legislature, SCE cannot predict with certainty what effects
the bill will have on SCE if it is enacted into law.
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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 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 issued its opinion affirming the federal district court on all claims, with the exception of the challenges founded
upon California state law, which the Ninth Circuit referred to the California Supreme Court.
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. The matter was returned to the Ninth Circuit for final disposition, and in December
2003, the Ninth Circuit unanimously affirmed the original stipulated judgment of the federal district court. In January 2004, the
Ninth Circuit 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.
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.
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. 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. The total amount recovered through PROACT was $3.6 billion. 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 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
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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. A decision on ERRA operations through June 30, 2003 is expected in the third quarter
of 2004.
On April 1, 2004, SCE submitted its second ERRA reasonableness review application requesting that the CPUC find that 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. A decision on this application is expected by the end of
2004.
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 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 (the amount of energy needed to serve SCE's customers from
sources other than its own generating plants, power-purchase contracts and California Department of Water Resources (CDWR) contracts)
position 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. SCE is currently 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.
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. 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's, Pacific Gas and Electric's (PG&E) and San Diego Gas & Electric's (SDG&E) are set to begin
August 30, 2004. A decision is expected by year-end 2004.
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Resource adequacy issues are being addressed in this proceeding on a parallel track, including a proposal to accelerate the phase-in
of the resource adequacy requirement from January 2008 to June 2006. SCE expects a CPUC decision on resource adequacy issues in
September 2004.
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 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.
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. In February 2001, a California law was enacted which authorized the CDWR to: (1) enter into
contracts to purchase electric power and sell power at cost directly to SCE's retail bundled customers; and (2) issue bonds to
finance those electricity purchases. 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.
The CPUC is currently considering the appropriate methodology for allocating CDWR's power charge revenue requirement for 2004 through
2013. PG&E, TURN, and SCE submitted a settlement agreement advocating that the costs of CDWR's long-term contracts be allocated on a
cost-follow-contracts basis, 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. On July 20, 2004, the CPUC issued two draft decisions that
would reject the proposed settlement agreement. Instead, the 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 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 ten-year period, it would institute a methodology that does
not provide the appropriate contract administration incentives to investor-owned utilities. A final decision on this matter is
expected in the third quarter of 2004.
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. The uncertainty over a post-2005 coal and water
supply has prevented SCE and other Mohave co-owners from making approximately $1.1 billion in Mohave-related investments (SCE's share
is $605 million), including the installation of pollution-control
Page 26
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.
Negotiations are continuing among the relevant parties in an effort to resolve the coal and water supply issues, but no resolution
has been reached. 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) 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, 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 approximately three years is likely. Evidentiary hearings took place in June and July of 2004, and a decision on this
matter is not expected before November 2004. 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 an impact on earnings.
San Onofre Steam Generators
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 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 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. SCE has not determined whether it will enter into contracts for steam generator fabrication in
the absence of CPUC approval of this memorandum account. If not, completion of steam generator replacement would likely be delayed
beyond the previously planned 2009 completion date. SCE is evaluating the impact of a delay.
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 and, in July 2004, amended its
application to the CPUC to reflect the fact that co-owner approval is not required to proceed with steam generator replacement.
SDG&E has elected to reduce its 20% ownership share rather than participate in the steam generator replacement project. The other
two co-owners, the cities of Riverside and Anaheim (who collectively own approximately 5% of the units), have not yet made an
election. The period during which such election can be made expires in October 2004. If steam generator replacement proceeds, upon
completion, SDG&E's ownership share of San Onofre Units 2 and 3, and the ownership shares of the cities if they elect to opt out,
would be reduced in accordance with the formula set forth in the operating agreement. If the parties do not agree on the application
of the formula, it will be subject to
Page 27
arbitration. The transfer of all or any portion of SDG&E's ownership share to SCE as a result of SDG&E's election not to participate
in steam generator replacement would require CPUC approval.
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 Nuclear Generating Station (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. As a result of the
implementation of the 2003 GRC decision, SCE recorded pre-tax net regulatory adjustments of $180 million as a credit to provision for
regulatory adjustment clauses during the second quarter of 2004. 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. This will result in an
approximate $55 million pre-tax gain in the third quarter of 2004. In addition, SCE expects to record approximately $48 million in
pre-tax gains related to the rate recovery of 1997-1998 generation-related capital additions and the related revenue requirement in
the third quarter of 2004, as a further result of the implementation of the 2003 GRC decision.
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. SCE has proposed that the GRC rate increase be combined with other rate changes from pending rate
proceedings and be effective August 5, 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
decision on this matter is expected in the fourth quarter of 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.
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In an April 22, 2004 CPUC 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 currently pursuing the appeal before the D.C. Circuit Court.
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)/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 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 any
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. Additional settlement payments
totaling approximately $134 million are due from El Paso over a 20-year period. In addition, 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 approximately $37 million in refunds and other payments
Page 29
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 April 26,
2004 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 that is expected to exceed $40 million. The Duke settlement remains
subject to the approval of the FERC and the CPUC. Additionally, 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.
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 June 30, 2004, the bark beetle CEMA had a balance of $91 million and the fire-related CEMA had a
balance of $10 million. SCE submitted an advice filing with the CPUC in June 2004 to recover approximately $18 million in bark
beetle-related costs incurred in 2003. SCE estimates that it will spend up to $135 million on this project in 2004, and will submit
an advice filing to recover these costs in 2005. SCE expects to submit an application with the CPUC in the third 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
Page 30
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 did not file a challenge to the decision as to the first priority issue, so the first priority
requirement is now final. The California Supreme Court has 60 days (extendable to 90 days) within which to accept or reject the
petition for review as to the jurisdiction issue.
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 service reliability, customer satisfaction, and employee safety. SCE
received two letters over the last year 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 2001 and 2002 are pending before the CPUC and have not been recognized in income by
SCE. SCE also had 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 widespread misconduct, SCE
proposed to refund to ratepayers all of the $12 million in PBR rewards that may be attributed 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 about $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 with respect to the customer satisfaction survey misconduct by severing the employment of several
supervisory personnel, updating system processes and related documentation
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for survey reporting, and implementing additional supervisory controls over data collection and processing.
As mentioned above, SCE is also eligible under its CPUC-approved PBR mechanism to earn rewards or penalties based on its performance
in comparison to CPUC-approved standards of service reliability and employee safety. In light of the problems uncovered with the
customer satisfaction surveys, SCE commenced investigations into the accuracy and completeness of SCE's service reliability and
employee safety reporting. While the safety and service reliability investigations are not yet complete, SCE has preliminarily
concluded that some of its data collection procedures for recording employee injuries may have been inadequate and some misreporting
may have occurred. SCE has not reached any conclusions as to the effect of those problems on the validity of safety incentive
performance payments. SCE has advised the CPUC staff of the existence of the safety and reliability investigations, promised to
provide copies of the investigative reports, and committed to return to ratepayers or forgo any PBR rewards that were earned based on
data shown to be inaccurate. Both the safety and the service reliability investigations are being pursued aggressively and will be
completed as soon as possible. Since the inception of PBR payments in 1997, SCE has received $20 million in employee safety
incentive performance payments and, based on SCE's records, may be entitled to an additional $15 million. As for service
reliability, since the inception of PBR payments in 1997, SCE has received $8 million in rewards based on frequency of outage data
and has applied for an additional $5 million award based on frequency of outage data for 2001.
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, service reliability and/or employee safety. 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.
OTHER DEVELOPMENTS
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 26 identified sites is $88 million. In third quarter 2003, SCE sold
certain oil storage and pipeline facilities. This sale caused a reduction in SCE's recorded estimated minimum environmental
liability. The ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties
inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified
sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the
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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 regulatory asset of $63 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 June 30, 2004 were $16 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 this matter 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.
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,
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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 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 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 District Court subsequently issued a scheduling order that imposes a December 31, 2004
discovery cut-off and sets a status conference for January 21, 2005. No trial date was established in the scheduling order. The
parties to the D.C. District Court action are currently engaged in scheduling and completing the remaining discovery in the case.
The Federal Circuit Court of Appeals, 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 Court of Appeals decision. Both petitions were denied on March 9, 2004. On March 16, 2004, the Court of
Appeals issued an order remanding the case against the Government to the Federal Court of 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 in the remanded Court of Federal Claims
case as a party 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.
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Results of Operations
Earnings from Continuing Operations
SCE earnings from continuing operations were $243 million and $344 million in the three- and six-month periods ended June 30, 2004,
respectively, compared to $226 million and $328 million in the same periods in 2003. The expiration of the ICIP mechanism at San
Onofre Nuclear Generating Station resulted in a decrease in earnings of $47 million. This decrease was more than offset by a
quarter-over-quarter benefit in regulatory adjustments of $55 million and improved operating results. The earnings impacts of these
positive regulatory items in the second quarter of 2004 ($107 million) from the implementation of the 2003 GRC decision were
partially offset by positive regulatory items that occurred in the second quarter of 2003 ($52 million) which included the tax
impacts of a FERC rate case and prior-period Palo Verde incentive awards. The reasons for the six-month period increase are the same
as the three-month period reasons discussed above.
Operating Revenue
SCE's retail sales represented approximately 83% and 85% of operating revenue for the three- and six-month periods ended June 30,
2004, respectively, and approximately 91% and 92% for the three- and six-month periods ended June 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 six-month periods ended June 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 and used to recover costs
incurred in 2003. There was no surcharge revenue recognized in 2004. The three- and six-month period decreases were partially
offset by the recognition of three months of revenue resulting from the consolidation of SCE's variable interest entities on March
31, 2004 (see "Critical Accounting Policies" and "New Accounting Principles") and 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. The six-month period decrease was 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 $546 million and $1.2 billion for the three- and
six month periods ended June 30, 2004, compared to $421 million and $845 million for the same periods in 2003.
Operating Expenses
Fuel expense increased in both the three- and six-month periods ended June 30, 2004, as compared to the same periods in 2003,
primarily due to the consolidation of SCE's variable interest entities, increased coal expense at SCE's Mohave coal facility due
increased generation in 2004, as compared to 2003, resulting from a planned outage and maintenance repairs in the second quarter of
2003. The six-month increase was partially offset by lower coal expense at SCE resulting from a first quarter 2004 scheduled major
overhaul at SCE's Four Corners coal facility.
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Purchased-power expense decreased in both the three- and six-month periods ended June 30, 2004, as compared to the same periods in
2003. The decreases were mainly due to the consolidation of SCE's variable interest entities and 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"). The decreases were partially offset by an increase in ISO-related costs, higher expenses
resulting from an increase in the number of gas bilateral contracts in 2004, as compared to 2003, and higher costs associated with
gas hedging activities resulting from higher realized and unrealized gains in 2003, as compared to 2004 mainly due to the expiration
of significant gas hedging instruments in 2003. The quarterly decrease was also partially offset by higher expenses related to power
purchased by SCE from qualifying facilities (QFs), as discussed below.
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. During the second quarter of 2004, spot natural gas prices were higher compared to the
same period in 2003.
Provisions for regulatory adjustment clauses - net decreased in both the three- and six-month periods ended June 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 $240 million for both the three- and six-month periods. The decreases also reflect a net
effect of approximately $180 million of regulatory adjustments 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 $50 million and $70 million associated with the bark beetle infestation for the three- and six-month
periods ended June 30, 2004, respectively (see "Regulatory Matters--Other Regulatory Matters--Catastrophic Event Memorandum Account").
SCE's 2003 GRC regulatory adjustments primarily relate to recognition of revenue from the rate recovery of pension contributions
during the time period that the pension plan was fully funded, the resolution over 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 three- and six-month period decreases were partially offset by the El Paso settlement payment received, of
which $66 million was refunded to customers through the ERRA account. The six-month period decrease was also due to the recovery of
approximately $115 million of gas hedging costs through regulatory mechanisms in 2003, 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 six-month periods ended June 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 general expenses,
primarily due to lower worker's compensation claims in 2004. The six-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 increased in both the three- and six-month periods ended June 30, 2004, as
compared to the same periods in 2003, due to an increase in SCE's nuclear decommissioning expense and an increase in SCE's
depreciation expense associated with additions to transmission and distribution assets.
Page 36
Other Income and Deductions
Interest and dividend income decreased in both the three- and six-month periods ended June 30, 2004, as compared to the same periods
in 2003, due to the absence of interest income on the PROACT balance at SCE 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 June 30, 2004 and increased in the six-month period ended June
30, 2004. The three-month period decrease was mainly due to the timing of recording Palo Verde nuclear incentives. During the
second quarter of 2003, SCE recorded 1999, 2000 and 2001 Palo Verde nuclear incentives approved by the CPUC. During the first
quarter of 2004, SCE recorded 2001 and 2002 Palo Verde nuclear incentives approved by the CPUC. The six-month period increase
reflects higher Palo Verde nuclear incentives at SCE in 2004, as compared to 2003.
Interest expense - net of amounts capitalized decreased in the three- and six-month periods ended June 30, 2004, mainly due to lower
long-term debt balances outstanding in 2004, as compared to 2003. The decrease was partially offset by a change in classification of
dividend payments on preferred securities to interest expense from dividends on preferred securities subject to mandatory redemption
effective July 1, 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 increased for both the three- and six-month periods ended June 30, 2004, compared to the same periods in 2003, primarily
due to an increase in pre-tax income as well as a reduction in 2003 tax expense related to the favorable resolution of a FERC rate
case. The increases were partially offset by changes in property-related flow-through taxes between periods.
SCE's composite federal and state statutory rate was approximately 40.5% for both periods presented. The lower effective tax rate of
39% realized in the three- and six-month periods ended June 30, 2004 was primarily due to dividend payment to the employee stock
ownership plan and property-related flow-through taxes.
Earnings from Discontinued Operations
Discontinued operations in 2003 reflect earnings from SCE's fuel oil pipeline and storage business, which was sold in the third
quarter of 2003.
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 $981 million for the six months ended June 30, 2004, and $1.4 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.
Page 37
Cash Flows from Financing Activities
Net cash provided by financing activities was $292 million for the six months ended June 30, 2004, compared to net cash used by
financing activities of $868 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.
During the first quarter of 2004, SCE issued $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 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 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, of which approximately
$196 million of these pollution-control bonds were reoffered. 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. Financing activities in 2004 also included dividend payments of $448 million of equity to Edison International.
During the six-month period ended June 30, 2003, SCE repaid $300 million of a one-year term loan due March 3, 2003, and $300 million
on its revolving line of credit, both of which were part of the $1.6 billion financing that took place in the first quarter of 2002.
In addition, SCE repaid $125 million of its 6.25% first and refunding mortgage bonds.
Cash Flows from Investing Activities
Net cash used by investing activities was $1.0 billion for the six months ended June 30, 2004, compared to $538 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 $721 million 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 $540 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 2006. The
construction work in progress for this project is recorded in nonutility property on Edison International's June 30, 2004 balance
sheet. SCE expects to finance the capital costs of the project with debt and equity consistent with its authorized capital structure.
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.
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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 273 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 22 contracts
with gas-fired cogeneration plants that contain variable pricing provisions based on the prices of natural gas. SCE requested from
the entities that hold these contracts the financial information necessary to determine whether SCE must consolidate these projects.
All 22 entities declined to provide SCE with the necessary financial information. However, four of the 22 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 18 projects in order to determine whether they should be consolidated by SCE. The
remaining 251 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 will adopt this guidance in third quarter 2004. If SCE's retiree health care plans
provide prescription drug benefits that are deemed to be actuarially equivalent to Medicare benefits, SCE will recognize the subsidy
in the measurement of its accumulated obligation and record an actuarial gain. Proposed federal regulations defining actuarial
equivalency are expected in third quarter 2004, with final regulations expected to be released by year-end 2004. Until the proposed
regulations are issued, SCE is unable to predict the effect of the new law on its postretirement health care costs and obligations.
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 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.
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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 June 30, 2004 are: 2005 -
$372 million; 2006 - $928 million; 2007 - $1.2 billion; 2008 - $183 million; 2009 - $219 million; and thereafter - $2.7 billion.
These amounts have been updated to reflect financing activities during the six months ended June 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 (2003 Form 10-K), and in Part II, Item 1 of SCE's Quarterly Report on Form 10-Q for
the period ending March 31, 2004 (First Quarter 10-Q).
CPUC Investigation Regarding SCE's Electric Line Maintenance Practices
Information about the CPUC's order instituting investigation regarding SCE's electric line maintenance practices appears in Part I,
Item 2, "Management's Discussion and Analysis of Financial Condition and Results of Operations" under the heading "Regulatory
Matters--Transmission and Distribution--Electric Line Maintenance Practices Proceeding" and is incorporated herein by this reference.
Information about the CPUC's order instituting investigation regarding SCE's electric line maintenance practices was previously
reported in Part I, Item 3 of the 2003 Form 10-K and in Part II, Item 1 of the First Quarter 10-Q.
County of San Bernardino Investigation
As previously reported in Part I, Item 3 of the 2003 Form 10-K, and in Part II, Item 1 of the First Quarter 10-Q, the County of San
Bernardino Office of District Attorney notified SCE, in a letter dated September 23, 2003, of its intent to file a misdemeanor
criminal complaint and a civil complaint seeking injunctive relief for the alleged failure to report a spill of oil from a
transformer in an isolated area of San Bernardino County. SCE entered into a stipulated judgment with the County of San Bernardino
on May 18, 2004 concerning the alleged failure to report the spill. Without admitting liability, the judgment provided that SCE pay
the sum of $125,604. The original penalty assessment according to the County of San Bernardino ranged from $5,604 to $555,604.
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Item 4. Submission of Matters to a Vote of Security Holders
At SCE's Annual Meeting of Shareholders on May 20, 2004, shareholders elected eleven nominees to the Board of Directors. The number
of broker non-votes for each nominee was zero. The numbers of votes cast for and withheld from each Director-nominee were as follows:
Numbers of Votes
- ----------------------------------------------------------------------------------
Name For Withheld
- ----------------------------------------------------------------------------------
John E. Bryson 459,609,308 410,316
France A. Cordova 459,594,086 425,538
Alan J. Fohrer 459,610,562 409,062
Bradford M. Freeman 459,612,356 407,268
Bruce Karatz 459,612,866 406,758
Luis G. Nogales 459,613,178 406,446
Ronald L. Olson 459,614,318 405,306
James M. Rosser 459,609,110 410,514
Richard T. Schlosberg, III 459,609,650 409,974
Robert H. Smith 459,625,406 394,218
Thomas C. Sutton 459,629,288 390,336
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Page 43
Item 6. Exhibits and Reports on Form 8-K
(a) Exhibits
3.1 Certificate of Amendment and Restated Articles of Incorporation of SCE effective June 1, 1993 (File No. 1-2313, Form
10-K for the year ended December 31, 1993)*
3.2 Certificate of Correction of Restated Articles of Incorporation of SCE dated effective August 21, 1997 (File No.
1-2313, Form 10-Q for the quarter ended September 30, 1997)*
3.3 Amended Bylaws of Southern California Edison Company as adopted by the Board of Directors effective May 20, 2004
(File No. 1-2313, SCE Form 8-K, dated May 21, 2004)*
10.1 Director 2004 Nonqualified Stock Option Terms and Conditions under the Equity Compensation Plan (File No. 1-9936,
filed as Exhibit 10.1 to the Edison International Form 10-Q for the quarter ended June 30, 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.
(b) Reports on Form 8-K:
Date of Report Date Filed Item(s) Reported
-------------- ---------- ----------------
May 7, 2004 May 11, 2004 12
May 20, 2004 May 21, 2004 5 and 7
- ----------------
** The May 11, 2004 Form 8-K reporting events under Item 12 was furnished under Item 12 and shall not be deemed to be "filed" for
purposes of the Securities and Exchange Act of 1934, nor shall it be deemed to be incorporated by reference in any filing under
the Securities Act of 1933.
Page 44
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned thereunto duly authorized.
SOUTHERN CALIFORNIA EDISON COMPANY
(Registrant)
By /s/ THOMAS M. NOONAN
--------------------------------
THOMAS M. NOONAN
Vice President and Controller
By /s/ KENNETH S. STEWART
--------------------------------
KENNETH S. STEWART
Assistant General Counsel and
Assistant Secretary
Dated: August 5, 2004