ML13326A862

Forwards Cash Flow Statement for Yr Ending 911231 & Annual Rept to Sec for Yr Ending 911231

ML13326A862
Person / Time
Site:	San Onofre, Palo Verde
Issue date:	05/12/1992
From:	Ulbricht T SOUTHERN CALIFORNIA EDISON CO.
To:	NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM)
References
NUDOCS 9205200144
Download: ML13326A862 (47)

Text

Southem California Edison Company P. 0. BOX 800 2244 WALNUT GROVE AVENUE ROSEMEAD, CALIFORNIA 91770 May 12, 1992 U.S. Nuclear Regulatory Commission Attention:

Document Control Desk Washington, D.C. 20555 Re:

Internal Cash Flow for San Onofre Units 1, 2 & 3 (Dockets 50-206, 50-361, 50-362) and Palo Verde Units 1, 2 & 3 (Dockets 50-528, 50-529, and 50-530)

Gentlemen:

The enclosed Cash Flow Statement for the year ending December 31, 1991 is submitted in accordance with Section 140.21 of CFP 140 for Southern California. Edison Company, San Diego Gas &

Electric Company, the City of Anaheim, and the City of Riverside for their ownership in San Onofre Nuclear Generating Units 1, 2, and 3 and for Southern California Edison Company's 15.8% share of Palo Verde Nuclear Generating Units 1, 2, and 3.

The Annual Report to the Securities and Exchange Commission (Form 10-K) for the year ending December 31, 1991 is also enclosed for your information.

If there are any questions regarding the material, please contact me at (818) 302-2808.

Sincerely, THERESA M. ULBRICHT, CPCU, ARM TMU:dgl Enclosures ltmu34 9--2 0- -200

-2 0-DR PDR ADOCK 05000206 PDR.

cc:

J. B. Martin, Regional Administrator, NRC Region V F. R. Huey, NRC Senior Resident Inspector, San Onofre 1,2&3 C. Tramell, NRC Project Manager, Palo Verde 1, 2 & 3 G. Kalman, NRR Project Manager, San Onofre 1 E. Kokajko, NRR Project Manager, San Onofre 2 & 3 Joe Rakowski, San Diego Gas & Electric Tom Vance, City of Anaheim Chuck Harris, City of Riverside Fred Lindy, Arizona Public Service

SOUTHERN CALIFORNIA EDISON COMPANY 1992 Internal Cash Flow Projection (Dollars in Thousands) 1991 1992 Actual Projected Net Income After Taxes

$629,500 Dividends Paid 627,900 Retained Earnings

$1,600 Adjustments:

Depreciation 758,900 794,900 Net Deferred Taxes & ITC 33,000 53,200 Allowance for Funds Used During Construction (27,900)

(31,500)

Total Adjustments

$764,000

$816,600 Internal Cash Flow

$765,600 Average Quarterly Cash Flow

$191,400 Percentage Ownership in All Nuclear Units:

San Onofre Nuclear Generating Station Unit 1 Southern California Edison Company 80.00%

San Diego Gas & Electric Company 20.00%

San Onofre Nuclear Generating Station Units 2 & 3 Southern California Edison Company 75.05%

San Diego Gas & Electric Company 20.00%

City of Anaheim 3.16%

City of Riverside 1.79%

Palo Verde Nuclear Generating Station Units 1-3 15.80%

Maximum Total Contingent Liability:

San Onofre Nuclear Generating Station Unit 1

$10,000 San Onofre Nuclear Generating Station Unit 2 10,000 San Onofre Nuclear Generating Station Unit 3 10,000 Palo Verde Nuclear Generating Station Unit 1 1,580 Palo Verde Nuclear Generating Station Unit 2 1,580 Palo Verde Nuclear Generating Station Unit 3 1,580

$34,740 Company policy prohibits disclosure of financial data which will enable unauthorized persons to forecast earnings or dividends, unless assured confidentiality. The Net Estimated Cash Flow for 1992 is expected to be comparable to the Actual Cash Flow for 1991.

0 SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 1991 Commission File Number 1-9936 SCEcorp (Exact nare of registrant as specified in its darter)

California 95-4137452 (State or other judediclion of (LRS. Employer incorporation or organization)

Identificaon No.)

2244 Walnut Grove Avenue (818) 302-2222 Rosemead, California 91770 (negistrane telephone number, (Address of prncipal executive oflices)

(21p Code)

Including area code)

Securities registered pursuant to Section 12(b) of the Act:

Name of each exchange Title of each class on which registered Common Stock New York and Pacific (also listed on London and Tokyo Exchanges)

Securities registered pursuant to Section 12(g) of the Act: None 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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K Is not contained herein, and will not be contained, to the best of registrant's knowledge, In definitive proxy or information statements incorporated by reference In Part III of this Form 10-K or any amendment to this Form 10-K. [

The aggregate market value of registrant's voting stock held by non-affiliates was approximately

$9,036,677,496 on or about February 21, 1992, based upon prices reported in the Western Edition of The Wall Street Journal. As of February 21, 1992, there were 221,080,795 shares of Common Stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE Portions of the following documents listed below have been incorporated by reference Into the parts of this report so indicated.

(1) Designated portions of the Annual Report to Shareholders for the year ended December 31, 1991..........................................

Parts I, II and IV (2) Designated portions of the Joint Proxy Statement relating to registrant's 1992 Annual Meeting of Shareholders.............................

Part III

TABLE OF CONTENTS Item Part I

1.

B usiness.....................................................

1 Business of SCEcorp............................................

1 Regulation of SCEcorp.........................................

1 Business of Southern California Edison Company........................

2 Regulation of Edison...........................................

2 Rate Matters.................................................

2 Fuel Supply.................................................

8 Environmental Matters.........................................

9 Business of The Mission Group and its Subsidiaries.......................

11

2.

Properties....................................................

12 Existing Utility Generating Facilities................................

12 El Paso Electric Company ("El Paso") Bankruptcy......................

14 Construction Program and Capital Expenditures......................

14 Nuclear Power Matters.........................................

15 Nuclear Waste Policy Act.......................................

16 Potential Competition..........................................

16

3.

Legal Proceedings..............................................

17 Antitrust M atters..............................................

17 Environmental Litigation........................................

18 Merger-Related Litigation........................................

19

4.

Submission of Matters to a Vote of Security Holders......................

19 Executive Officers of the Registrant 20 Part II

5.

Market for Registrant's Common Equity and Related Stockholder Matters......

21

6.

Selected Financial Data...........................

21

7.

Management's Discussion and Analysis of Results of Operations and Financial Condition............................................

21

8.

Financial Statements and Supplementary Data..........................

21

9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure...........................................

21 Part III

10.

Directors and Executive Officers of the Registrant........................

21

11.

Executive Compensation..........................................

21

12.

Security Ownership of Certain Beneficial Owners and Management...........

21

13.

Certain Relationships and Related Transactions..........................

22 Part IV

14.

Exhibits, Financial Statement Schedules, and Reports on Form 8-K...........

22 Report of Independent Public Accountants on Supplemental Schedules.......

24 Signatures....................................................

41 Exhibit Index..................................................

43

PART I Item 1. Business Business of SCEcorp SCEcorp was incorporated on April 20, 1987, under the laws of the State of California for the purpose of becoming the parent holding company of Southern California Edison Company ("Edison"), a California public utility corporation. SCEcorp owns all of the issued and outstanding common stock of Edison and, in addition, owns all of the issued and outstanding capital stock of The Mission Group ("Mission Group"),

which in turn owns the stock of subsidiaries engaged in nonutility businesses. These subsidiaries are currently engaged in developing cogeneration and other energy projects (Mission Energy Company),

developing and investing in real estate projects (Mission Land Company), and making financial investments in electric generating facilities and other assets (Mission First Financial).

SCEcorp is engaged solely in the business of holding for investment the stock of its subsidiaries and is not presently conducting any independent business activities. For the year ended December 31, 1991, Edison and Mission Group accounted for 83% and 17%, respectively, of the net income of SCEcorp. At December 31, 1991, Edison had 17,110 employees and Mission Group and its subsidiaries had 401 employees. Currently, SCEcorp has no employees of its own.

The principal executive offices of SCEcorp are located at 2244 Walnut Grove Avenue, Rosemead, California 91770, and its telephone number is (818) 302-2222.

Regulation of SCEcorp SCEcorp and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the Public Utility Holding Company Act of 1935 ("Holding Company Act") on the basis that SCEcorp and Edison are incorporated in the same state and their business is predominately intrastate in character and carried on substantially in the state of incorporation. It is necessary for SCEcorp to file an annual exemption statement with the Securities and Exchange Commission ("SEC"), and the exemption may be revoked by the SEC upon a finding that the exemption may be detrimental to the public interest or the interest of investors or consumers. SCEcorp has no intention of becoming a registered holding company under the Holding Company Act.

SCEcorp is not a public utility under the laws of the State of California and is not subject to regulation as such by the California Public Utilities Commission ("CPUC"). See "Business of Southern California Edison Company-Regulation of Edison" below for a description of the regulation of Edison by the CPUC.

However, the CPUC decision authorizing Edison to reorganize Into a holding company structure contains certain conditions, which, among other things, ensure the CPUC access to books and records of SCEcorp and its affiliates which relate to transactions with Edison; require SCEcorp and its subsidiaries to employ accounting and other procedures and controls to ensure full review by the CPUC and to protect against subsidization of nonutility activities by Edison's customers; require that all transfers of market, technological or similar data from Edison to SCEcorp or its affiliates be made at market value; preclude Edison from guaranteeing any obligations of SCEcorp without prior written consent from the CPUC; provide for royalty payments to be paid by SCEcorp or its subsidiaries in connection with the transfer of product rights, patents, copyrights or similar legal rights from Edison; and prevent SCEcorp and its subsidiaries from providing certain facilities and equipment to Edison except through competitive bidding. In addition, the decision provides that Edison shall maintain a balanced capital structure in accordance with prior CPUC decisions, that Edison's dividend policy shall continue to be established by Edison's Board of Directors as though Edison were a comparable stand-alone utility company, and that the capital requirements of Edison, as determined to be necessary to meet Edison's service obligations, shall be given first priority by the Boards of Directors of SCEcorp and Edison.

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Business of Southern California Edison Company The following is a discussion of the business of Edison, which presently accounts for the major portion of SCEcorp's revenues and earnings. For SCEcorp's business segment Information for each of the three years ended December 31, 1991, 1990 and 1989, see Note 12 of "Notes to Consolidated Financial Statements" contained in the 1991 Annual Report to Shareholders Incorporated by reference in this report.

Edison was incorporated in 1909 under California law and is a public utility primarily engaged in the business of supplying electric energy to a 50,000 square-mile area of central and southern California, excluding the City of Los Angeles and certain other cities. This area includes some 800 cities and communities and a population of more than 10 million people. As of December 31, 1991, Edison had 17,110 employees.

During 1991, 36.7% of Edison's total operating revenue was derived from commercial customers, 34.6% from residential customers, 15.5% from Industrial customers, 8.2% from public authorities, 3.4% from agricultural and other customers and 1.6% from resale customers. Its principal executive offices are located at 2244 Walnut Grove Avenue, Rosemead, Califomia 91770, and its telephone number Is (818) 302-1212.

Regulation of Edison Edison's retail operations are subject to regulation by the CPUC. The CPUC has the authority to regulate, among other things, retail rates, Issuances of securities and accounting and depreciation practices.

Edison's resale operations are subject to regulation by the Federal Energy Regulatory Commission ("FERC").

The FERC has the authority to regulate resale rates as well as other matters, including transmission service pricing, accounting and depreciation practices and licensing of hydroelectric projects.

Edison is subject to the jurisdiction of the Nuclear Regulatory Commission ("NRC") with respect to its nuclear power plants. NRC regulations govern the granting of licenses for the construction and operation of nuclear power plants and subject those power plants to continuing review and regulation.

The construction, planning and siting of Edison's power plants within California are subject to the jurisdiction of the California Energy Commission and the CPUC. Edison is subject to rules and regulations promulgated by the California Air Resources Board and local air pollution control districts with respect to the emission of pollutants into the atmosphere, the regulatory requirements of the California State Water Resources Control Board and regional boards with respect to the discharge of pollutants into waters of the state and the requirements of the California Department of Toxic Substances Control with respect to handling and disposal of hazardous materials and wastes.

Edison is also subject to regulation by the U.S.

Environmental Protection Agency ("EPA"), which administers certain federal statutes relating to environmental matters. Certain other federal, state and local laws and regulations relating to environmental protection, land use and water rights also impact Edison.

The California Coastal Commission has continuing jurisdiction over the construction permit for San Onofre Nuclear Generating Station ("San Onofre") Units 2 and 3. Although the units are on line, the permit remains open and the Coastal Commission can order further modification of the units. This jurisdiction may continue for several years because it Involves oversight on mitigation measures arising from the permit.

The Department of Energy ("DOE") has regulatory authority over certain aspects of Edison's operations and business relating to energy conservation, solar energy development, power plant fuel use and disposal, coal conversion, public utility regulatory policy and natural gas pricing.

Rate Matters CPUC Retail Ratemaking The rates for electricity provided by Edison to its retail customers comprise several major components established by the CPUC to compensate Edison for basic business and operational costs, fuel and purchased power costs, and the costs of adding major new facilities.

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Basic business and operational costs are recovered through base rates, which are determined In general rate case proceedings held before the CPUC every three years. During a general rate case, the CPUC critically reviews Edison's operations and general costs to provide service (excluding energy costs and, in certain instances, major plant additions). The CPUC then determines the revenue requirement to cover those costs, including items such as depreciation, taxes, cost of capital, operation, maintenance, and administrative and general expenses. The revenue requirement is forecasted on the basis of a specified test year.

Base rates may be adjusted in the years between general rate case years through an attrition year allowance. The attrition year allowance is Intended to allow Edison to recover, without lengthy hearings, specific uncontrollable cost changes in its base rate revenue requirement and, thereby, preserve Edison's opportunity to earn its authorized rate of return in the years that are not general rate case test years.

Edison's fuel, purchased power and energy-related costs of providing electrical service are recovered through a balancing account mechanism called the Energy Cost Adjustment Clause ("ECAC"). Under the ECAC balancing account procedure, fuel, purchased power and energy-related revenues and costs are compared and the difference is recorded as either an undercollection or overcollection. The amount recorded in the balancing account is periodically amortized through rate changes which return overcollections to customers by reducing rates or collect undercollections from customers by Increasing rates. The costs recorded in the ECAC balancing account are subject to review by the CPUC and allowed for rate recovery only to the extent they are found to be reasonable. Certain Incentive provisions are included in the ECAC that can affect the amount of fuel and energy-related costs actually recovered. Edison is required to make an ECAC filing for each calendar year, and must also make a second filing for a mid-year adjustment if such filing would result in an ECAC rate change exceeding 5% of total annual revenue.

The CPUC has also used the mechanism of an Annual Energy Rate ("AER") In the form of a fixed rate designed to recover a portion of the estimated annual fuel cost applicable for Inclusion In the ECAC. The AER is set on a forecast basis and is not subject to balancing account treatment. The CPUC suspended the AER in 1988, reinstated it in February 1990, and then suspended it again In August 1990 subject to further investigation.

Another balancing account mechanism Is the Major Additions Adjustment Clause ("MAAC") used by the CPUC to reflect the revenue requirement associated with the costs of owning, operating and maintaining major new facilities.

The MAAC procedure allows Edison to recover in rates, subject to refund, a portion of the revenue requirement associated with its investment in major new facilities. The amount recovered in rates and the recorded revenue requirement are compared each month and the difference recorded in a balancing account. The procedure remains in effect until the CPUC renders a decision on the reasonableness of Edison's investment, at which time, the revenue requirement associated with the reasonable level of investment is placed in base rates and the amounts in the balancing account are amortized.

For Edison's interest in the three units of the Palo Verde Nuclear Generating Station ("Palo Verde"),

the CPUC has adopted a 10-year rate phase-in plan which provides for the deferral of $200,000,000 of investment-related revenue during the first four years of operations for each of the three units, commencing on their respective commercial operation dates. Revenue deferred for each unit under the plan for years one through four was $80,000,000, $60,000,000, $40,000,000 and $20,000,000, respectively. The deferrals and related interest are being recovered on a levelized basis in the final six years of the phase-in plan as applied to each unit.

The CPUC has also adopted a nuclear unit incentive procedure which provides for a sharing of additional energy costs or savings between Edison and its ratepayers when operation of any of the units of San Onofre or Palo Verde is outside a specified target capacity factor range. For San Onofre Units 2 and 3, and Palo Verde Units 1, 2 and 3 the target capacity factor range Is 55% to 80% of their rated capacity, and for San Onofre Unit 1 the range is 55% to 75%.

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.0

@0 An additional balancing account mechanism has been adopted by the CPUC primarily to minimize the effect on earnings of fluctuations in retail kilowatt-hour sales.

General Rate Case ('GRC')

On November 18, 1991, the CPUC issued a final decision authorizing Edison an overall rate of return of 10.59%, which includes a return on common equity of 12.65%, for 1992. Edison had requested an overall rate of return of 11.09%, including a 13.65% return on common equity, but during the course of hearings agreed to the rates of return that were authorized by the CPUC. Edison's 1991 authorized overall rate of return and return on common equity were 10.71% and 12.85%, respectively. The decrease in the authorized rates of return from 1991 to 1992 will result in a negative impact of about 5 cents in Edison's earnings per share for 1992. On December 20, 1991, the CPUC announced its decision on the 1992 GRC application.

The CPUC authorized a $72,000,000 or 1% increase in revenues, effective January 20, 1992. Edison had requested a $203,000,000 revenue increase to recover projected Increases In operation and maintenance expenses and capital-related costs. A CPUC administrative law judge ("AU") had recommended a

$66,000,000 decrease in revenue and denial of Edison's request to capitalize software development and research, development and demonstration ("RD&D") costs incurred prior to 1992. The CPUC deferred a decision on the capitalization issue and has allowed Edison to file additional information supporting its position. These items could total as much as $100,000,000. Further, on January 23, 1992, Edison filed an Application for Rehearing on issues related to software development and RD&D capitalization, health care escalation and the San Onofre Unit 1 capital modification cost cap. The CPUC is expected to act on the Application for Rehearing by March 23, 1992.

The GRC decision was consolidated with several other rate decisions authorized by the CPUC for a total rate increase of $138,000,000, or 1.9%, which includes revenue Increases for Edison's investment in Palo Verde Unit 3, funding of postretirement benefits other than pensions, and recovery of expenses for the Cool Water Coal Gasification Program, partially offset by revenue decreases for Edison's lower 1992 authorized rate of return on rate base and lower forecasted fuel and purchased-power expenses.

Hearings on a separate portion of Edison's GRC, dealing with rate design and revenue allocation for rates to become effective in June 1992, were held in December 1991 and a final CPUC decision is expected in May 1992.

Edison is implementing a restructuring program to reduce costs and provide a reasonable opportunity to earn the 12.65% return on common equity which the CPUC authorized for 1992.

Energy Cost Adjustment Clause The CPUC's Division of Ratepayer Advocates ("DRA"), which periodically reviews the reasonableness of utility expenses, recommended in December 1988 that the CPUC disallow recovery of part of the expenses incurred by Edison for power purchased from the Kern River Cogeneration Company ("KRCC"),

a nonutility power producer. Mission Energy Company, a nonutility subsidiary of SCEcorp, owns a 50%

interest in KRCC. In September 1990, after conducting hearings on the DRA recommendation, the CPUC disallowed recovery of $48,000,000 of Edison's power expenses (including Interest) paid to KRCC between mid-1 985 and late 1987. The CPUC based the disallowance on the conclusion that the contract is essentially for the purchase of "as-available" rather than "firm" capacity. If the same principles were applied to expenses incurred by Edison from late 1987 through year-end 1991, the disallowance would increase to $105,000,000 (including interest). Future KRCC disallowances, if any, would be less significant than those through 1991 due to forecasted increases in the price of as-available capacity in subsequent years. The CPUC did not impose the more stringent restrictions on affiliated transactions that were recommended by the DRA.

In an application for rehearing, Edison contested the amount of the disallowance, arguing that if the CPUC treats the capacity delivered under the contract on an as-available basis, it should treat the energy that KRCC delivered on the same basis. In December 1990, the CPUC granted Edison's request for a rehearing to determine the appropriate level of disallowance for the mid-1 985 through late 1987 period. An AU denied a February 1991 request by the DRA for reconsideration of the rehearing decision. In testimony filed in May 1991, Edison argued that pricing the energy on an as-available basis would reduce the KRCC 4

disallowance to approximately $13,000,000 (including Interest) for the period between mid-1985 and late 1987.

In November 1990, the DRA recommended that the CPUC disallow recovery of part of the expenses incurred by Edison for power purchased from the Sycamore Cogeneration Company ("Sycamore") and the Watson Cogeneration Company ("Watson") during late 1987 through early 1989. Mission Energy Company owns 50% of the Sycamore project and 49% of the Watson project. The recommended disallowances for Sycamore and Watson, which total $37,000,000 and $14,000,000 (both excluding Interest), respectively, were based on different reasons than the KRCC decision. The recommended disallowance for Sycamore included

$33,000,000, primarily based on the DRA's allegations that Edison should have terminated or renegotiated the contract in 1985, and $4,000,000 based on the assertion that the energy price could exceed avoided cost. The DRA's recommended $14,000,000 disallowance for Watson was primarily based on allegations that Edison overpaid Watson for both capacity and energy during late 1987 through early 1989. The CPUC has not issued a decision on this matter.

The DRA also has been reviewing payments made to KRCC between late 1987 and early 1991 and to 12 other nonutility power producers owned partially by Mission Energy. The DRA has not issued reports on these matters.

On November 1, 1991, Edison and the DRA announced an agreement in principle to settle disputes relating to Edison's power purchases from the 13 nonutility generation facilities partially owned by Mission Energy. The settlement resolves affiliate issues related to the formation and administration of these contracts from their inception through December 31, 1991.

Edison also has agreed not to enter into new power purchase contracts with Mission Energy.

The agreement provides for a one-time disallowance of

$120,000,000 and a reduction in the amount Edison can recover in the future for power purchased from these affiliates. In total, the settlement will result in disallowances, in present value terms, of approximately

$250,000,000, which is fully reflected in Edison's financial statements. On January 31, 1992, Edison made a supplemental filing to allow DRA review of power purchased from the 13 affiliate projects for the period April 1, 1991, through December 31, 1991, the entire period covered by the settlement. By early April 1992, Edison and the DRA expect to file a definitive agreement for CPUC approval and a decision is expected In late 1992.

In January 1992, the DRA recommended the CPUC disallow $7,300,000 in power purchase payments made between late 1987 and early 1990 to nonutility power producers. This recommendation is based on an allegation that Edison improperly pays firm capacity prices for power delivered in excess of the nonutility generator's contract capacity. The DRA also has recommended that the CPUC direct Edison to change its method of calculating firm capacity payments to these nonutility generators in the future.

The DRA's December 1988 report recommended a disallowance of $3,000,000 in power purchase payments made in 1987 to Pacific Power & Light Company ("PP&L") and $6,000,000 related to fuel oil carrying charges and contract administrative matters, for the period from late 1987 through early 1989. In 1990, the DRA recommended an additional $17,000,000 disallowance associated with the PP&L contract, and in 1991 the DRA recommended penalties and disallowances totalling approximately $11,000,000:

$1,800,000 associated with fuel oil carrying costs and $9,200,000 associated with nuclear generation and fuel. A CPUC decision, issued in May 1991, found the execution of the PP&L contract reasonable and rejected the DRA's 1988 recommended disallowance. As a result, the DRA withdrew its 1990 and 1991 recommendations for disallowances associated with the PP&L contract for the 1989 and 1990 periods. The DRA also withdrew its recommendations for disallowances associated with fuel oil carrying costs of

$1,900,000 in the 1989 ECAC and $1,800,000 in the 1991 ECAC. Finally, in December 1991 Edison and the DRA reached an agreement on the appropriate level of nuclear related penalties and disallowances, and made a joint recommendation to the CPUC. If adopted, the DRA proposed nuclear related disallowance will be reduced from $9,200,000 to $2,300,000. A CPUC decision is expected in mid-1992.

In a decision issued In Edison's 1992 GRC, the CPUC ordered Edison to file additional testimony on all nuclear refueling outages during the review periods in its current ECACs on: (1) incremental base rate operation and maintenance costs of shortening refueling outages; and (2) incremental replacement power costs associated with extending refueling outages. The CPUC has not yet scheduled the submission of the testimony or hearings on this matter.

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In December 1990, the CPUC issued a decision adopting an ECAC rate increase of $459,000,000, which when combined with previously approved revenue changes authorized in other proceedings resulted in a consolidated net revenue increase effective January 1, 1991, of $464,000,000.

In May 1991, Edison filed a request for a $214,000,000 annual revenue Increase in Its ECAC rates for service beginning January 20,1992. In a January 10, 1992 decision, the CPUC reduced authorized revenues related to the ECAC rates by $53,000,000. The decision consolidated several other rate decisions as follows:

(i) a $71,000,000 revenue increase to recover Edison's Investment in Palo Verde Unit 3; (ii) a $46,000,000 revenue Increase to fund post-retirement benefits other than pensions; (ill) a $26,000,000 Increase to recover expenses for a former coal gasification demonstration program; and (iv) a $48,000,000 increase in revenues pursuant to the CPUC's decision in Edison's 1992 GRC. The combined effect of all the foregoing decisions is a rate increase of $138,000,000, which became effective January 20, 1992.

Edison owns 15.8% of Palo Verde which is a three-unit plant located near Phoenix, Arizona, operated by Arizona Public Service Company (APS").

In its May 1990 ECAC application, Edison reported to the CPUC that Palo Verde Unit 1 ended its second fuel cycle in February 1990 with a gross capacity factor of 37.3%. Edison's share of the penalty for this cycle under the nuclear unit incentive procedure is $5,300,000.

Palo Verde Unit 2 ended its second fuel cycle in June 1990 with a gross capacity factor of 54.87%. Edison's share of the penalty for this cycle is $41,000. San Onofre Unit 1 ended its tenth fuel cycle In February 1991 as the result of a refueling during an outage to inspect and repair the thermal shields Inside the reactor; and its gross capacity factor for this cycle was 44.0%. Edison's share of the penalty for this cycle is $1,680,000.

The CPUC is expected to issue an ECAC decision on the reasonableness of these penalties in mid-1992.

Palo Verde Outage Review In March 1989, Palo Verde Units 1 and 3 experienced automatic shutdowns. Since the resultant outages overlapped previously scheduled refueling outages, normal refueling, maintenance, inspection, surveillance, modification and testing activities were conducted at the units, as well as modifications to the plants required by the NRC. Unit 3 was restored to service on December 30, 1989, and Unit 1 was restored to service on July 5, 1990.

On December 18, 1989, the CPUC instituted an investigation into the outages pursuant to the California Public Utilities Code ("Code"). The Code requires the CPUC to institute an Investigation when any portion of a utility's generating facilities has been out of service for nine consecutive months. The CPUC order required that the subsequent collection of rates associated with Palo Verde Units 1 and 3 be subject to refund pending its review of the outages. Pursuant to the order, Edison established a memorandum account to track the relevant costs. The CPUC will also review the reasonableness of Edison's purchase of replacement power and fuel during the outages. In July 1991, the CPUC modified the order to include only the revenue collected during each unit's outage as revenue subject to refund, beginning on the date the investigation was initiated and ending after 100 hours0.00116 days <br />0.0278 hours <br />1.653439e-4 weeks <br />3.805e-5 months <br /> of continuous operation at full power.

On November 1, 1991, the DRA issued a report recommending disallowance for $59,000,000 of revenue collected during the outages: $4,600,000 for capital projects deemed to be unnecessary and the cost of replacement power during the outages. Edison estimates the cost of replacement power at $70,000,000 to

$80,000,000. On February 3, 1992, the AU In Edison's ECAC proceeding ruled that the reasonableness of the Palo Verde Unit 2 outage be consolidated with the Units 1 and 3 investigation. The DRA will file its testimony on Unit 2 in late March 1992. Edison will file its testimony on the reasonableness of the outages in late April 1992. Edison believes these costs were reasonably Incurred and should be recovered in rates.

Hearings on this matter will be held in 1992.

Mohave Order Instituting Investigation (Oll)

On July 1, 1986, Edison filed its response to the CPUC's Oil regarding the outage resulting from the rupture of a high pressure steam line at the Mohave Generating Station ("Mohave") on June 9, 1985. The 6

Oil will review Edison's share of repair costs and replacement fuel and energy related costs associated with the outage. On July 28, 1986, Edison filed an addendum to the July 1, 1986, response asserting that the CPUC's adoption of the Coal Plant Incentive Procedure precludes any review of reasonableness by the CPUC regarding replacement fuel and purchased power costs Incurred during the outage. Edison subsequently incurred costs of approximately $90,000,000, net of insurance recoveries, to repair damage from the accident and provide replacement power during the six-month outage.

On May 29, 1991, the DRA and its consultant issued reports alleging that Edison imprudently operated the Mohave plant and therefore contributed to the accident. As a result, the DRA recommended that all expenses Incurred because of the accident be bome by Edison shareholders. The DRA did not quantify the level of its proposed disallowance. Edison believes that metallurgical and physical characteristics of a weld reduced the otherwise expected pipe life to the point of failure after 15 years of service. Edison Is vigorously contesting the DRA's and its consultant's allegations. Edison plans to file testimony on this matter by April 1992 and hearings are expected in late 1992.

High Voltage Direct Current Expansion Project ('HVDCEP')

The HVDCEP began operation in April 1989. Since July 1, 1989, Edison has been charging its retail customers 0.017 e/kWh, subject to refund, to recover its investment in the project. Edison's 1988 general rate case authorized this charge, which is designed to recover 75% of the investment-related costs. The collection of the remaining costs is deferred until the CPUC has determined the Investment was reasonably incurred. In October 1989, Edison filed a report with the CPUC requesting recovery of $72,600,000 In project costs. In June 1990, the DRA issued its findings that, with the exception of $1,200,000 In accounting related adjustments, all other funds were reasonably expended. Subsequently, a negotiated adjustment of $150,000 was agreed upon and a settlement agreement was submitted to the AU. The settlement, if adopted by the CPUC, will allow Edison full recovery of approximately $72,450,000 In rates. A CPUC decision Is expected in the third quarter of 1992. The DRA has recommended that this rate recovery, if adopted, remain subject to adjustment pending a final determination of the cost-effectiveness of the project In light of the power exchange agreement between Edison and the Los Angeles Department of Water and Power.

Cool Water Coal Gasification Program ('Program')

Edison participated in the Cool Water Coal Gasification Program, an unincorporated association, which owned and operated an Integrated coal gasification-combined cycle facility (approximately 100 megawatts

("MW") (net)) at Edison's Cool Water Generating Station. Upon completion of the Program's five-year demonstration period on June 23, 1989, ownership of the facility was transferred to Edison In return for Edison's assumption of the Program's liability for termination expenses. Pursuant to CPUC order, Edison prepared, and filed In June 1990, an application to recover its deferred capital cost and other deferred expenses approximating $84,000,000. In February 1991, the DRA issued its report recommending Edison be authorized recovery of approximately $52,000,000. After additional discovery and discussions with Edison, the DRA withdrew $20,100,000 of its original recommended disallowance. In July 1991, the DRA and Edison submitted a joint recommendation for recovery of $78,100,000 of Edison's deferred costs. On October 23, 1991, the CPUC Issued a decision adopting the joint recommendation and authorizing Edison to transfer the balance of $78,100,000 to Edison's ECAC balancing account for recovery beginning January 1, 1992. A subsequent decision issued January 10, 1992, authorized Edison to recover that amount over three years beginning January 1992. Edison presently is negotiating with Texaco for the sale of the facility.

FERC Resale Ratemaking Edison sells electricity to six southern Califomia cities (Anaheim, Azusa, Banning, Colton, Riverside and Vernon), the Southern California Water Company and APS under rates subject to FERC jurisdiction.

In accordance with FERC procedures, resale rates are subject to refund with interest if subsequently disallowed. Edison believes refunds from pending rate proceedings, if any, would not have a material effect on the results of operations.

7

Fuel Supply Fuel and purchased-power costs amounted to approximately $2.9 billion in 1991, a 0.4% increase over 1990. Sources of energy and unit costs of fuel for 1987 through 1991 were as follows:

-vrg Cost Per Mion Sources of Enew BTIJs(1)

Year ended December 31, Year ended December 31, 1987 1988 1989 1990 1991 1987 1988 1969 19

_]i Oil...........................

1%

4%

4%

2%

$3.25

$2.78

$3.03

$4.39

$4.07 Natural Gas...................

36 23 24 17 18%

2.55 3.25 3.24 3.02 2.81 Nuclear (2)....................

20 21 17 20 21 1.15 1.02 1.04 0.94 0.87 Coal........................

14 14 13 13 14 1.04 1.06 1.14 1.21 1.15 All Fuels.....................

71 62 58 52 53 2.03 1.99 2.15 1.90 1.84 Hydroelectric(3)................

5 4

4 3

4 Purchased Power (3):

Firm.......................

6 7

6 3

3 Economy...................

8 9

7 13 8

Other power producers:

Biomass.................

1 1

1 2

2 Cogeneration 6,

13 17 19 20 Geothermal...............

2 2

5 6

7 Solar....................

0 1

1 1

1 W ind....................

1 1

1 1

2 Total 100%

100%

100%

100%

100%

(1) British Thermal Unit ("BTU") is the standard unit of measure for the heat content of fuels. One BTU Is the amount of heat required to raise the temperature of one pound of water, at 39.1 degrees Fahrenheit, by one degree Fahrenheit.

(2) The average nuclear fuel costs for 1987 includes costs for Palo Verde Units 1 and 2.

(3) There are no fuel costs associated with these categories.

Average fuel costs, expressed in cents per kilowatt-hour, for the year ended December 31, 1991, were:

oil, 4.37.; natural gas, 2.94t; nuclear,.93c; and coal, 1.18t.

Natural Gas and Fuel Oil Supply A number of Edison's major steam electric generating units are designed to burn oil or natural gas as primary boiler fuels. Although natural gas is expected to be Edison's principal fuel during the next several years, the extent of Edison's use of natural gas as boiler fuel Is dependent upon the amount of gas available from Edison's gas suppliers, the interstate pipeline capacity available to bring gas to California and applicable federal and state laws and regulations. Edison will be forced to rely on fuel oil if its use of natural gas Is restricted.

Air pollution control laws and regulations applicable to most of Edison's oil-and gas-fired steam electric generating plants have required that fuel oil utilized by Edison not exceed a sulfur level of 0.25%. As of December 31, 1991, Edison had In inventory approximately 6.4 million barrels of low sulfur fuel oil In inventory. To the extent oil utilization exceeds current forecasts, additional supplies are expected to be available from purchases made on the spot market and under an option agreement.

8

Nuclear Fuel Supply Edison has contractual arrangements covering 100% of the projected nuclear fuel cycle requirements for San Onofre through the years indicated below:

Units Unit 1 2A.3 Uranium concentrates()...............................

1995 1995 Conversion........

1995 1995 Enrichment........................................

1998 1998 Fabrication........

2001 2000 Spent fuel storage(2).................................

2005 2005 (1) Assumes the San Onofre participants meet their supply obligations in a timely manner.

(2) Assumes full utilization of expanded on-site storage capacity and normal operation of these units, including interpool transfers and no full-core reserve. If additional storage or permanent disposal Is unavailable when storage limits are reached, other arrangements will be required, the availability or cost of which Edison cannot predict at this time. The Nuclear Waste Policy Act of 1982 requires that the DOE provide for the disposal of utility spent nuclear fuel beginning in 1998. The DOE has stated that it is unlikely that it will be able to start accepting spent nuclear fuel at its permanent repository before 2010. However, the DOE has undertaken a program for establishing a Monitored Retrievable Storage Facility which could accept spent nuclear fuel in 1998.

Participants In Palo Verde have purchased uranium concentrates sufficient to meet projected requirements through 1997. Independent of arrangements made by other participants, Edison will furnish its share of uranium concentrates requirements through at least 1995 from existing contracts. Contracts to provide conversion services cover requirements through 1994. Enrichment and fabrication contracts will meet Palo Verde requirements through 1995 and 1994, respectively.

Palo Verde on-site expanded spent fuel storage capacity will accommodate needs through 2010 for Units 1 and 3 and 2009 for Unit 2.

Environmental Matters Legislative and regulatory activities in the areas of air and water pollution, waste management, hazardous chemical use, noise abatement, land use, aesthetics and nuclear control continue to result in the imposition of numerous restrictions on Edison's operation of existing facilities and on the timing, cost, location, design, construction and operation by Edison of new facilities required to meet its future load requirements. These activities substantially affect future planning and will continue to require modifications of Edison's existing facilities and operating procedures. They also increase the risk of forced abandonment of construction projects with a resultant loss of design, engineering and construction costs and the payment of cancellation charges, which in the aggregate could be substantial.

The Clean Air Act provides the statutory framework to implement a program for achieving national ambient air quality standards and provides for maintenance of air quality In areas exceeding such standards.

The Clean Air Act was amended in 1990, giving the South Coast Air Quality Management District

("SCAQMD") 20 years to achieve all the federal air quality standards. The SCAQMD's Air Quality Management Plan ("AQMP"), adopted in 1991, demonstrates a commitment to attain federal air quality standards within 20 years.

Consistent with the requirements of the AQMP and the Clean Air Act Amendments of 1990, the SCAQMD adopted rules to reduce emissions of oxides of nitrogen ("NOx") from combustion turbines and utility boilers. These rules require Edison to reduce NOx emissions at its Long Beach Combined Cycle Facility by 55% by 1996.

Edison will have to reduce its in-basin boiler NOx emissions by 86% from 1990 permitted emission rates by the year 2000. In Ventura County, a NOx rule was adopted requiring an 88% NOx reduction by June 1996 at all utility boilers. Edison's expected total cost to meet these rule requirements could cost up to $960,000,000 of in-service dollars.

9

0

• 0*

The Clean Air Act Amendments of 1990 ("CAAA) do not require any significant additional emissions control expenditures that are identifiable at this time. The amendments call for a five-year study of the sources and causes of regional haze in the southwestern U.S. It is not known the extent to which this study may require sulfur dioxide emission reductions at the Mohave plant. The acid rain provisions of the amended Clean Air Act also put an annual limit on sulfur dioxide emissions allowed from power plants.

Edison estimates that it receives more sulfur dioxide allowances than it requires for its projected operations.

The CAAA also requires the EPA to carry out a three-year study of risk to public health from emissions of toxic air contaminants from power plants, and to regulate such emissions only If required. In response to a petition by Mohave County In the state of Arizona, a study Is also being carried out by the Nevada Department of Environmental Protection to evaluate the Impact of the plume from the Mohave plant on the air quality in the Mohave area. The potential regulatory outcome could require Edison to meet a new lower opacity limit by as early as 1996. The capital cost to meet the new rule requirements could be up to

$340,000,000 of In-service dollars or about $190,000,000 for Edison's share.

Regulations under the Clean Water Act require the obtaining of permits for the discharge of certain pollutants into the waters of the United States. Under this act the EPA Issues effluent limitation guidelines, pretreatment standards and new source performance standards for the control of certain pollutants.

Individual states may Impose still more stringent limitations. In order to comply with guidelines and standards applicable to steam electric power plants, Edison is incurring additional expenses and capital expenditures. Edison presently has discharge permits for all applicable facilities. Additional regulations will be issued but Edison is unable to predict the extent to which such additional regulations will affect its operations and capital expenditure requirements.

The Safe Drinking Water and Toxic Enforcement Act prohibits the exposure to Individuals of chemicals known to the State of California to cause cancer or reproductive harm and the discharge of such listed chemicals into potential sources of drinking water. Additional chemicals are continuously being put on the state's list, requiring constant monitoring by Edison.

The State of California has adopted a policy discouraging the use of fresh water for plant cooling purposes at inland locations. Such a policy, when taken in conjunction with existing federal and state water quality regulations and coastal zone land use restrictions, could substantially Increase the difficulty of siting new generating plants anywhere in California.

Edison has identified 41 sites for which it is actively or potentially responsible for remediation under environmental laws. Environmental authorities set the timing of investigation and remediation at these sites.

Edison has estimated the minimum liability on 12 of these sites at $40,000,000 and has accrued this amount.

The 29 remaining sites are currently not a high priority for environmental authorities, and investigations will proceed as dictated by these authorities. Upon completion of Investigations, some or all of these sites may require remedial action. Due to the absence of any extensive investigations, Edison cannot reliably estimate the total cost of investigation and remediation for the 29 remaining sites.

Nineteen of the 41 sites identified are former manufactured gas plant sites.

Edison's cleanup responsibility for these sites is based on Edison's, or a predecessor company's, ownership or operation of the plants. These gas plants were operated for the production of gas prior to the widespread availability of natural gas. The EPA and the California Department of Toxic Substances Control have determined that specified constituents of the gas plant by-products are hazardous substances or hazardous wastes, and may require removal or other remedial action.

In 1988, the CPUC established an advice letter procedure for rate recovery of environmental cleanup costs, which is expected to permit subsequent recovery of all material investigation and remediation costs, subject to a reasonableness review.

As a result, Edison recorded a $40,000,000 regulatory asset representing the future recovery in rates of its estimated minimum costs to complete Investigation and remediation. In July 1991, Edison filed for a reasonableness review of costs incurred at three of the 41 sites.

Edison expects to make an additional filing on or before March 31, 1992. Hearings on both applications are expected to be completed by the end of 1992.

10

The Resource Conservation and Recovery Act ("RCRA") provides the statutory authority for the EPA to implement a regulatory program for the safe treatment, recycling, storage and disposal of solid and hazardous wastes. Thus far, the EPA's regulations have had only a minimal economic impact on environmental expenditures. However, a significant report is still before the EPA and Congress regarding the disposition of high volume coal wastes. As a result of the study performed by the EPA over the past few years, the EPA will recommend to Congress that high volume coal combustion wastes (fly ash/bottom ash) not be regulated as hazardous under RCRA. With or without congressional approval, Edison will incur additional expenses to either completely change its disposal practices or to modify existing disposal facilities and monitoring systems.

The Toxic Substance Control Act and accompanying regulations govern the manufacturing, processing, distribution in commerce, use and disposal of polychlorinated biphenyls, a toxic substance used in certain electrical equipment. Regulations to date have had a substantial Impact on environmental expenditures.

The effect of Edison's use of low-sulfur fuel oil required by air quality regulation is discussed in "Natural Gas and Fuel Oil Supply" under "Fuel Supply".

Edison's capitalized expenditures for environmental protection for the years 1969 through 1991 and its currently estimated capital expenditures for such purpose for the years 1992 through 1996 are as follows:

(i thousands)

Air Waler Sold Addional Pollution Pollutan Waste Noise Plant Year Total Control Control Abatnent Aesthelics Capaci scellaneous 1969-1991....

$3,354,610

$650,082

$260,298

$40,026

$12,750

$2,174,592

$16,531

$200,331 1992...........

230,539 62,821 4,230 1,913 757 146,117 14,700 1993..........

406,304 233,488 614 689 745 155,456 15,311 1994...........

330,118 164,138 14 712 250 160,852 4,151 1995...........

324,841.

152,825 980 266 170,494 276 1996...........

292,738 114,315 1,001 797 175,972 653 These estimates include budgeted and forecasted plant expenditures responsive to currently effective legislation. Projected capital expenditures for environmental protection are subject to continuous review and periodic revisions because of escalation in engineering and construction costs, additions and deletions of planned facilities, changes in technology, evolving environmental regulatory requirements and other factors beyond Edison's control. Edison believes that costs incurred for these environmental purposes will be recognized by the CPUC and the FERC as reasonable and necessary costs of service for rate recovery purposes.

Business of The Mission Group and its Subsidiaries The Mission Group was incorporated in 1987 to own the stock and coordinate the activities of several companies engaged in nonutility businesses. The principal subsidiaries of The Mission Group are Mission Energy Company ("Mission Energy"), Mission First Financial ("Mission Financial") and Mission Land Company

("Mission Land"). A fourth subsidiary, Mission Power Engineering Company ("Mission Power"), discontinued operations in 1990. The businesses of these companies are described below. For SCEcorp's business segment Information for each of the three years ended December 31, 1991, 1990 and 1989, see Note 12 of "Notes to Consolidated Financial Statements" contained In the 1991 Annual Report to Shareholders incorporated by reference in this report.

On December 31, 1991, The Mission Group had consolidated assets of $2.1 billion and, for the year then ended, had consolidated revenue of $204,800,000 and consolidated net income of $116,100,000.

The Mission Group's principal executive offices are located at 18101 Von Karman Avenue, #1700, Irvine, California 92715.

11

Mission Energy. Mission Energy, primarily through its subsidiary corporations, is engaged in the business of developing, owning, and operating cogeneration, small power, geothermal, and other principally energy-related projects. At December 31, 1991, Mission Energy subsidiaries held partnership interests in 27 operating power production facilities with an aggregate power production capability of approximately 2,843 megawatts ("MW"), of which more than 1,165 MW are attributable to Mission Energy's interests. These operating facilities are located in California, Nevada, New Jersey, Pennsylvania, Maine, Virginia and Washington. In addition, facilities aggregating more than 1,106 MW are in construction or advanced permitting stages. Mission Energy owns interests in oil and gas producing operations and related facilities in Canada and U.S. locations in Texas, Alabama, New Mexico, offshore Louisiana and California.

At December 31, 1991, Mission Energy had total consolidated assets of $1.2 billion and for the year then ended had consolidated revenue of $154,200,000 and consolidated net Income of $82,500,000.

Currently, most of Mission Energy's operating power production facilities are qualifying facilities under the Public Utility Regulatory Policies Act of 1978 ("PURPA") and the regulations promulgated thereunder.

Qualifying facility status exempts the projects from the application of the Holding Company Act, many provisions of the Federal Power Act, and state laws and regulations respecting rates and financial or organizational regulation of electric utilities. Mission Energy, through wholly-owned subsidiaries, also has passive ownership interests in two operating independent power projects that have been reviewed for compliance with the Holding Company Act. In addition, some Mission Energy subsidiaries have made fuel related investments and a limited number of non-energy related investments.

While qualifying facility status entitles projects to the benefits of PURPA, each project must still comply with other federal, state and local laws, including those regarding siting, construction, operation, licensing and pollution abatement.

Mission Financial. Mission Financial participates in investment opportunities involving leveraged leasing, project finaricing, affordable housing and cash management. Its investments Include interests in nuclear power, cogeneration, waste-to-energy, hydroelectric and affordable housing facilities. Since its inception in 1987, Mission Financial has invested in 50 projects. In 1991, it invested in the Huntington Resource Recovery Project, and two new Boeing 767 aircraft that are leased to American Airlines. In addition, six affordable housing projects were completed and placed in service.

At December 31, 1991, Mission Financial hadtotal consolidated assets of $690,200,000 and, for the year then ended, had consolidated revenue of $30,500,000 (including interest income) and consolidated net income of $24,500,000.

Mission Land. Mission Land is engaged, directly and through its subsidiaries, in the business of developing, owning and managing industrial parks and other real property investments. Mission Land owns and manages commercial and industrial buildings in industrial parks located in Brea, Chino, Garden Grove, and Rancho Cucamonga, California. Mission Land and its subsidiaries also have interests in industrial, residential and commercial real estate in Ontario, California; Tolleson, Arizona; Munster, Indiana; Chicago, Illinois and in other locations.

At December 31, 1991, Mission Land had total consolidated assets of $264,200,000 and for the year then ended had consolidated revenue of $27,300,000 and consolidated net income of $9,200,000.

Item 2.

Properties Existing Utility Generating Facilities Edison owns and operates 12 oil-and gas-fueled electric generating plants, one diesel-fueled generating plant, 37 hydroelectric plants and an undivided 80% interest (349 MW net) in Unit 1 and an undivided 75.05%

interest (1,614 MW net) in Units 2 and 3 at San Onofre. These plants are located in central and southern California. Palo Verde (15.8% Edison-owned, 579 MW net) is located near Phoenix, Arizona. Palo Verde 12

Units 1, 2 and 3 started commercial operation on February 1, 1986, September 19, 1986, and January 20, 1988, respectively. Edison owns two units at a small oil-and gas-fueled electric generating plant in Arizona and a 48% undivided interest (754 MW) in Units 4 and 5 at the Four Corners Generating Station ("Four Corners Project"), a coal-fueled steam electric generating plant in New Mexico, all of which are operated by other utilities. Edison operates and owns a 56% undivided interest (885 MW) in Mohave, which consists of two coal-fueled steam electric generating units in Clark County, Nevada. Edison receives an entitlement of 277 MW from the DOE's Hoover Dam Hydroelectric Project. At year-end 1991, the existing Edison-owned generating capacity (summer effective rating) was comprised of approximately 62% gas and oil, 18% nuclear, 12% coal and 8% hydroelectric.

San Onofre, the Four Corners Project, certain of Edison's substations and portions of its transmission, distribution and communication systems are located on lands of the United States or others under (with minor exceptions) licenses, permits, easements or leases or on public streets or highways pursuant to franchises. Certain of such documents obligate Edison, under specified circumstances and at its expense, to relocate transmission, distribution and communication facilities located on lands owned or controlled by federal, state or local governments.

With certain exceptions, major and certain minor hydroelectric projects, with related reservoirs, currently having an effective operating capacity of 1,154 MW and located in whole or in part on lands of the United States, are owned and operated under governmental licenses which expire at various times between 1992 and 2012. Such licenses Impose numerous restrictions and obligations on Edison, including the right of the United States to acquire the project upon payment of specified compensation. When existing licenses expire, FERC has the authority to Issue new licenses to third parties, but only if their license application Is superior to Edison's and then only upon payment of specified compensation to Edison. Any new licenses issued to Edison are expected to be issued upon terms and conditions less favorable than those of the expired licenses. Applications of Edison for the relicensing of certain of the hydroelectric projects referred to above with an aggregate effective operating capacity of 89.9 MW are pending. Annual licenses issued for all Edison projects, whose licenses have expired and are undergoing relicensing, will be renewed until the new licenses have been issued.

In 1991, Edison's peak demand was 16,709 MW, set on October 2, 1991. At the time of this peak, the total area system operating capacity available to Edison was 20,875 MW. The peak experienced in 1991 was about 940 MW below the previous peak set on June 27, 1990.

Substantially all of the properties of Edison are subject to the lien of a trust indenture securing First and Refunding Mortgage Bonds (Trust Indenture"), of which approximately $4.3 billion principal amount was outstanding at December 31, 1991. Such lien and Edison's title to its properties are subject to the terms of franchises, licenses, easements; leases, permits, contracts and other instruments under which properties are held or operated, certain statutes and governmental regulations, liens for taxes and assessments, and liens of the trustees under such indenture. In addition, such liens and Edison's title to its properties are subject to certain other liens, prior rights and other encumbrances, none of which, with minor or unsubstantial exceptions, affects Edison's right to use such properties in its business, unless the matters with respect to Edison's interest in the Four Corners Project and the related easement and lease referred to below may be so considered.

Edison's rights in the Four Corners Project, which is located on land of The Navajo Tribe of Indians under an easement from the United States and a lease from The Navajo Tribe, may be subject to possible defects. These defects include possible conflicting grants or encumbrances not ascertainable because of the absence of, or inadequacies in, the applicable recording law and the record systems of the Bureau of Indian Affairs and The Navajo Tribe, the possible inability of Edison to resort to legal process to enforce its rights against The Navajo Tribe without Congressional consent, possible impairment or termination under certain circumstances of the easement and lease by The Navajo Tribe, Congress or the Secretary of the Interior and the possible invalidity of the lien of Edison's trust Indenture against Edison's interest In the easement and lease and the improvements thereon.

13

El Paso Electric Company ("El Paso") Bankruptcy El Paso owns or leases a 15.8% interest in Palo Verde and owns a 7% interest in Units 4 and 5 of the Four Corners Project. On January 8, 1992, El Paso filed a voluntary petition to reorganize under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Western District of Texas. Pursuant to an agreement among the participants in Palo Verde and an agreement among the participants in Four Corners Units 4 and 5, each participant is required to fund its proportionate share of operation and maintenance, capital and fuel costs of Palo Verde and Four Corners Units 4 and 5. The participation agreements provide that if a participant fails to meet its payment obligation, each non-defaulting participant must pay its proportionate share of the payments owed by the defaulting participant. On February 13, 1992, the bankruptcy court approved a stipulation between El Paso and APS, as the operating agent of Palo Verde, pursuant to which El Paso agreed to pay its proportionate share of all Palo Verde invoices delivered to El Paso after February 6, 1992. El Paso agreed to make these payments until such time, if ever, the bankruptcy court orders El Paso's rejection of the participation agreement governing the relations among the Palo Verde participants. The stipulation also specifies that approximately $9,200,000 of El Paso's Palo Verde payment obligations invoiced prior to February 7, 1992, are to be considered "pre-petition" general unsecured claims of the other Palo Verde participants.

Construction Program and Capital Expenditures On February 24, 1992, a CPUC AU issued a proposed decision which would require Edison to add 735 MW of new generating resources during the next decade. The proposal includes "Identified Deferrable Resources" of: Geothermal -

100 MW in 1997 and 200 MW in 1999; Wind - 50 MW In 1997; and Repower 385 MW in 1998.

Fifty percent of each wind and geothermal generation would be "set-aside" for renewables. Edison argued in the proceedings that its resource needs for the next decade can be met using cost-effective conservation in conjunction with existing power plants. This approach would result in the lowest total energy cost to customers. A decision by the CPUC is expected in spring 1992 which could result in a resource solicitation by Edison in fall 1992.

Cash required by SCEcorp for its capital expenditures totaled $838,000,000 in 1989, $905,000,000 in 1990 and $986,000,000 in 1991. Construction expenditures for the 1992-1996 period are estimated (as of January 16, 1992, the date of SCEcorp's latest approved budget) as follows:

(in millions) 1992 1993 1994 1995 j.

Total Electric generating plant...................................

$ 323 $ 518 $ 501 $ 512 $ 364

$ 2,218 Electric transmission lines and substations.......................................

159 109 106 127 229 730 Electric distribution lines and substations........................................

423 409 423 461 486 2,202 Other expenditures.......................................

163 116 107 105 81, 572 Nonutility expenditures...................................

49 5

5 5

69 Total...........................................

1,117 1,157 1,142 1,210 1,165 5,791 Less: allowance for funds used during construction..............

__3 32 33 33 33 164 Cash required for construction expenditures...................

E 1.125 $1.109 $1.177 51.32 L

Edison's construction program and related expenditures are continuously reviewed and periodically revised because of changes in estimated system load growth, rates of inflation, receipt of adequate and timely rate relief, the availability and timing of environmental, siting and other regulatory approvals, the scope of modifications required by regulatory agencies, the availability and costs of external sources of capital, the development of new technology and other factors beyond Edison's control.

As a result of the completion of San Onofre Units 2 and 3 and Palo Verde Units 1, 2 and 3, construction work in progress has been significantly reduced. The reduction in construction work in progress caused allowance for funds used during construction ("AFUDC"), which does not represent current cash Income, to decline accordingly.. Pre-tax AFUDC represented 4.0% of earnings for the year 1991.

14

In addition to the cash required for construction expenditures for the next five years as discussed above, $1.7 billion Is needed to meet requirements for long-term debt maturities, and sinking fund and preferred stock redemption requirements. The majority of these capital requirements are expected to be met by Internally generated sources.

Edison's estimates of cash available for operations for the five years through 1996 assume, among other things, the receipt of adequate and timely rate relief and the realization of its assumptions regarding cost increases, Including the cost of capital. Edison's estimates and underlying assumptions are subject to continuous review and periodic revision.

The timing, type and amount of all additional long-term financing are also influenced by market conditions, rate relief and other factors, Including limitations Imposed by Edison's Articles of Incorporation and Trust Indenture.

Nuclear Power Matters Although higher energy costs will be incurred for replacement generation during any periods the San Onofre and Palo Verde Units are not in operation, substantially all such costs will be included in future ECAC filings. Edison cannot predict what other effects, if any, legislative or regulatory actions may have upon it or upon the future operation of the San Onofre or Palo Verde Units or the extent of any additional costs it may incur as a result thereof, except for those that follow.

San Onofre Unit 1 In July 1991, Edison submitted an application requesting the CPUC to find future operation of San Onofre Unit 1 cost-effective and to authorize recovery of capital expenditures of approximately $100,000,000 through 1994. These expenditures are required by the NRC in order to operate Unit 1 beyond its current fuel cycle, which is forecasted to end in late 1992. Edison's July 1991 Application was consolidated with the Biennial Resource Plan Update ("Update") shortly after its filing. In a September 1991 report, the DRA concluded continued operation of Unit 1 is not cost-effective and recommended the unit be shut down and its book value amortized over four years with no return allowed. Alternatively, the DRA recommended that if the CPUC finds continued operation is cost-effective, Edison should recover the cost of its proposed expenditures and future operations at Unit 1 through performance-based ratemaking. Hearings were held on these issues in the Update proceeding in October 1991.

On February 7, 1992, a Settlement Agreement was signed by Edison, San Diego Gas & Electric Company ("SDG&E") and the DRA and was filed with the CPUC. This Settlement Agreement resolves issues related to San Onofre Unit 1 considered in the October 1991 Update hearings, and San Onofre Unit 1 ratebase issues considered in Edison's 1992 GRC decision.

Pursuant to the Settlement Agreement: (1) Edison will cease operation of San Onofre Unit 1 no later than the end of the current fuel cycle between late 1992 and mid-1993; (2) Edison will be able to recover in rates its remaining net investment in San Onofre Unit 1 of approximately $350,000,000 over a four-year amortization period; (3) The four-year amortization period will start upon CPUC approval of the Settlement Agreement and Edison will receive its CPUC-authorized rate of return on the unamortized balance prior to the shutdown of San Onofre Unit 1; (4) After shutdown of San Onofre Unit 1, which will occur sometime between late 1992 and mid-1 993, Edison will earn a lower rate of return on the remaining unamortized San Onofre Unit 1 investment which, after taxes, is fixed at 8.98% over the remainder of the amortization period; and (5) $23,000,000 of the $33,000,000 of San Onofre Unit 1 investment removed from Edison's ratebase in the 1992 GRC decision will be restored to Edison's ratebase.

Parties to the Update and the 1992 GRC filed comments on the Settlement Agreement on March 9, 1992. Edison believes the comments do not raise material issue of fact and, therefore the CPUC could proceed to make a decision on the Settlement Agreement without further hearings.

15

San Onofre Units 2 and 3 In 1974, the California Coastal Commission, as a condition of the San Onofre Units 2 and 3 coastal permit, established a three-member Marine Review Committee (MRC") to assess the marine environmental effects caused by the Units. In August 1989, the MRC issued its final report which found, in part, that San Onofre Units 2 and 3 caused adverse effects to several species of marine life.

On July 16, 1991, the Coastal Commission revised the coastal permit for Units 2 and 3 and required Edison to restore 150 acres of degraded wetlands, construct a 300-acre artificial kelp reef, and Install fish behavioral barriers inside the Units' cooling water intake structure. Based on the MRC findings, the California Regional Water Quality Control Board, San Diego Region, heard testimony on October 31, 1991, regarding whether to issue a cease and desist order based on allegations Edison violated its wastewater discharge permits. At a February 10, 1992 meeting, the Regional Board determined the allegations of permit violations were not supported by the evidence and abandoned the cease and desist order proceedings.

Nuclear Facility Decommissioning Edison's share of costs to decommission nuclear facilities is estimated to be $211,400,000 for San Onofre Unit 1; $232,100,000 for San Onofre Unit 2; $319,100,000 for San Onofre Unit 3; $43,100,000 for Palo Verde Unit 1; $40,500,000 for Palo Verde Unit 2; and $43,800,000 for Palo Verde Unit 3. These costs are all in 1991 dollars.

Edison is currently collecting $106,484,000 annually in rates for its share of decommissioning costs for San Onofre Units 1, 2 and 3 and Palo Verde Units 1, 2 and 3.

Nuclear Insurance Edison operates its nuclear units in accordance with prudent utility practices and In conformity with NRC regulations. Edison generally carries the maximum Insurance coverage reasonably available to protect against damage to its nuclear units and replacement energy costs In the unlikely event of an accident at any nuclear unit. A description of this insurance is included in Note 10 of "Notes to Consolidated Financial Statements" incorporated herein. Although Edison believes an accident at its nuclear units is extremely unlikely, in the event of an accident, regardless of fault, Edison's insurance coverage might be inadequate to cover the losses to Edison. In addition, such an accident could result in action by the NRC to suspend operation of the damaged unit. Furthermore, the NRC could suspend operation at Edison's undamaged nuclear units and the CPUC and FERC could deny rate recovery of related costs. Such an accident, therefore, could materially and adversely affect the operations and earnings of Edison.

Nuclear Waste Policy Act Pursuant to the Nuclear Waste Policy Act of 1982, Edison, acting as agent for the San Onofre participants, has entered into a contract with the DOE for disposal of spent nuclear fuel for San Onofre Units 1, 2 and 3. Under the terms of the contract, Edison is required to pay a quarterly fee of one mill per kilowatt hour to the DOE for net nuclear power generated and sold on and after April 7, 1983. For generation prior to April 7, 1983, the contract requires payment of a one-time fee equivalent to one mill per kilowatt hour, plus accrued interest. This one-time fee has been recorded as a deferred asset pending future rate recovery and, including accrued interest, was approximately $13,573,000 on December 31, 1991. The obligation for this one-time fee is being discharged by equal payments over 40 quarters. Such payments commenced during 1985. Expenses associated with disposal of spent nuclear fuel are recovered through the ECAC procedure.

Potential Competition Under various acts of Congress, federal power projects have been constructed In Califomla and neighboring states. Municipally owned utilities, cooperative utilities and other public bodies have certain preferences over investor-owned utilities in the purchase of electric power provided by federally funded power projects and, in addition, have certain preferences over investor-owned utilities in connection with the 16

.O e

acquisition of licenses to build and/or operate hydroelectric power plants. Any energy which is or may be generated at these projects and transmitted for the account of such other utilities and public bodies over present or future government or utility-owned lines into the territory or markets served by Edison would result in a loss of sales by Edison.

Under the laws of California, utility districts may Include Incorporated as well as unincorporated territory.

Such districts, as well as municipalities, have the right to construct, purchase or condemn and operate electric facilities. In addition, when a city owning an electric system annexes adjacent unincorporated territory which Edison has previously served, Edison may experience a loss of customers.

Edison's construction permits for San Onofre Units 2 and 3 contain certain conditions which require Edison (i) on timely notice, to permit privately or publicly owned utilities, including Edison's resale customers within or adjacent to Edison's service area, to participate on mutually agreeable terms in future nuclear units initiated by Edison, and (ii) to interconnect and coordinate reserves with, furnish emergency service to, sell bulk power to and purchase bulk power from, and provide certain transmission services for such utilities.

Edison has also entered into agreements with certain of its resale customers which contemplate their possible participation in jointly owned generating projects Initiated by Edison, and the Integration of power sources acquired by each such customer, including the dispatching, reserve sharing, partial power-supply requirements and transmission service required in connection with such integrated operations. Pursuant to these agreements, two resale customers exercised an option to participate in Edison's ownership entitlement in San Onofre Units 2 and 3. Effective November 1, 1977, Edison sold an undivided 3.45% interest in San Onofre Units 2 and 3 to these two resale customers for approximately $90,000,000. Effective September 1, 1981, a further 1.5% interest in Units 2 and 3 was sold to one of these resale customers for approximately

$50,000,000. In addition, since 1986, six of Edison's resale customers have acquired ownership interests in other generating sources and made purchases from other utilities in such amounts as to decrease Edison's revenues from resale cities from 4.4% to 1.6% of sales. This revenue loss has not had a substantial effect on Edison's business and opportunities.

PURPA has fostered the entry of nonutility companies into the electric generation business. Under PURPA, nonutility power producers are allowed to construct qualifying facilities ("QFs") for the production of electricity from certain alternative or renewable energy resources, and utilities are required to purchase the electrical output of these QFs at prices set pursuant to state regulations and, In the future, pursuant to a CPUC-approved competitive bidding process.

Edison is required by contracts and state regulation to continue to buy power generated by QFs, under long-term contracts negotiated earlier at prices that are often higher than the power Edison can produce or purchase from other sources. Further, certain operators of OFs sell power they produce to large Industrial and commercial customers of Edison from projects located on-site. Further loss of sales from such customers may be aggravated in the future as a result of attempts by these producers to institute mandatory "wheeling" -

unlimited access to public utility transmission lines. Edison opposes any attempt to Impose mandatory wheeling. Edison is presently managing contracts with OF developers to reduce ratepayer impacts and to more closely match Edison's needs with proposed development.

Item 3.

Legal Proceedings Antitrust Matters On March 2, 1978, five resale customers (the California cities of Anaheim, Azusa, Banning, Colton and Riverside, the "Cities") filed suit against Edison in the United States District Court for the Central District of California alleging violation of certain antitrust laws. The complaint seeks monetary damages, a trebling of such damages and certain injunctive relief. The complaint alleges Edison (i) Is engaged in anti-competitive behavior by charging more for electricity sold to the resale customers than Edison charged certain classes of its retail customers ("price squeeze"), and (ii) has taken action alone and in concert with other utilities to prevent or limit such resale customers from obtaining bulk power supplies from other sources to reduce or replace the resale customers' purchases from Edison ("foreclosure"). The plaintiffs estimated their actual damages for alleged price squeeze at approximately $22,780,000 before trebling, and foreclosure damages 17

g0@

stemming from alleged loss of energy and capacity at approximately $76,800,000 before trebling, for the period February 1, 1978, to December 31, 1985. The trial began on July 8, 1986, and concluded on September 26, 1986. Proposed Findings of Fact and Conclusions of Law were filed by Edison with the Court on November 21, 1986. A final judgment in favor of Edison on all Issues was entered on October 24, 1990.

On November 15, 1990, the Cities filed their Notice of Appeal of the decision to the Ninth Circuit Court of Appeals. Oral argument was held on October 11, 1991. On February 7, 1992, the Court of Appeals affirmed the District Court's decision in favor of Edison on all claims.

In 1983, another resale customer, the City of Vernon, filed a complaint against Edison in the United States District Court for the Central District of California, alleging violation of certain antitrust laws. The complaint alleges that Edison has engaged in anticompetitive behavior by restricting access to Edison transmission facilities and foreclosing Vernon from purchasing bulk power supplies from other sources. The complaint also alleges that Edison unlawfully designed its resale rates in certain respects. Vernon has claimed damages of approximately $60,000,000 before trebling. By means of a Minute Order dated March 1, 1990, the Court granted three motions for Summary Judgment in favor of Edison. On March 9, 1990, the Court filed a formal decision granting two of the motions. Final judgment In favor of Edison was filed on August 31, 1990. On October 23, 1990, Vernon filed its Notice of Appeal of the District Court decision with the Ninth Circuit Court of Appeals. Oral argument was held on October 11, 1991. On February 7, 1992, the Court of Appeals affirmed the District Court's rulings on all issues but one, involving injunctive relief only and remanded that issue back to the District Court for consideration. On February 21, 1992, Vernon filed a petition for rehearing and requested a rehearing en banc.

On January 31, 1991, California Energy Company ("CEC") filed a lawsuit in United States District Court for the Northern District of California against SCEcorp, Edison, several nonutility subsidiaries, selected individuals, and Kidder, Peabody & Co. (the "Defendants"). The complaint has been amended three times, most recently on November 18, 1991. The allegations are antitrust violations of the Sherman Act, conspiracy to interfere with contractual relations and common law unfair competition. CEC asks for treble damages as proved at trial for antitrust violations and compensatory and punitive damages for the pendent claims.

Furthermore, CEC requests that SCEcorp divest itself of Mission Energy.

On October 31, 1991, the District Court heard the Defendants' motion to dismiss. SCEcorp and Edison argued that CEC has not suffered any cognizable antitrust injury and antitrust claims are barred by the state action doctrine. The motion was denied. However, the denial does not reflect any opinion on the ability of CEC to prove the allegations.

On January 6, 1992, the Defendants' filed an answer to the third amended complaint, denying all allegations against it and asserting numerous affirmative defenses. The case is In the discovery phase with trial scheduled for February 15, 1993.

Environmental Litigation On November 8, 1990, an environmental organization and two individuals filed a lawsuit against Edison in United States Federal District Court for the Southern District of California. The lawsuit alleges Edison's operation of San Onofre Units 2 and 3 is in violation of National Pollutant Discharge Elimination System Permits. The basis for the allegations Is a report prepared for the California Coastal Commission on the effects of the generating station. The plaintiffs request that the court enjoin operation of Units 2 and 3, impose civil penalties, and order Edison to repair the alleged damage to the marine environment. On April 8, 1991, the Court considered a motion filed by Edison for a stay In the proceedings and a motion filed by the plaintiffs for a preliminary Injunction. The Court denied both motions. On November 8, 1991, the Court established a schedule of events, including conferences, discovery, and settlement negotiations, leading to trial in December 1992. Edison believes the favorable decision by the Regional Water Quality Control Board on February 10, 1992, as discussed in Item 2, "Properties, Nuclear Power Matters", will assist the Court in reaching a decision favorable to Edison.

18

Merger-Related Litigation On March 3, 1989, a purported class action complaint was filed on behalf of SDG&E shareholders naming as defendants SCEcorp, Edison, individual defendants and SDG&E. The complaint was served on Edison on March 30, 1989. In the complaint, plaintiffs allege, among other things, that the Individual SDG&E directors (i) breached their fiduciary duties by Implementing "anti-takeover" measures intended to deny SDG&E's shareholders the highest possible value for their shares, and (II) have been and will be unjustly enriched as a result of increased compensation and benefits derived from SCEcorp's and Edison's acquisition of SDG&E at the expense of SDG&E and its shareholders. Tucson Electric Power Company

("TEP"), SCEcorp and Edison (the "Companies") are named as alleged alders, abettors and co-conspirators In derivative and class claims for breach of fiduciary duty, abuse of control and unjust enrichment. Plaintiffs seek the following relief: (a) a declaration that the action is a proper class and derivative action; (b) an order enjoining the payment by SDG&E to TEP of a $25,000,000 fee arising out of the Tucson Settlement Agreement; and (c) an order compelling the defendants to, among other things, account to plaintiffs for increased compensation and benefits derived from the Companies' proposed acquisition of SDG&E.

Plaintiffs also seek unspecified compensatory damages and other monetary relief. The Companies believe the allegations contained in the complaint are without merit. The parties other than TEP are negotiating principles for settlement.

On September 5, 1990, TEP filed a suit In Superior Court in San Diego, California, alleging Interference with TEP's merger agreement with SDG&E. The complaint asked for unspecified compensatory damages plus $6.7 billion in punitive damages. On September 17,1990, TEP filed an amended complaint that added a class action claim which the court later dismissed.

On November 7, 1990, the Companies filed a demurrer on the grounds that (a) TEP could not state a claim for relief, and (b) TEP shareholders lacked standing to maintain a claim. After a hearing on December 5, 1990, the Superior Court sustained both challenges. TEP then filed an amended complaint, to which the Companies demurred. After a hearing on April 26, 1991, the Superior Court sustained the challenge to the TEP shareholder claims, but overruled the other challenge. The Companies appealed the Superior Court denial to the California Court of Appeal. On August 29, 1991, after the Court of Appeal declined to hear the petition, the California Supreme Court ordered the Court of Appeal to hear the petition on its merits. The matter was argued and the Court of Appeals denied the petition on February 11, 1992. The Companies petitioned the California Supreme Court for review and that petition is pending.

On September 3, 1991, the Companies filed a Summary Judgment Motion with the Superior Court, arguing that both the Companies' offer and conduct in connection with its lawful competing bid were not tortious as a matter of law. The Superior Court denied the Companies' motion on the grounds that these arguments presented factual issues. On December 17, 1991, the Companies petitioned the Court of Appeal for review and that petition is pending.

The Companies deny all of TEP's allegations of wrongdoing and are vigorously defending against all charges. Trial Is scheduled for July 17, 1992.

Item 4. Submission of Matters to a Vote of Security Holders Inapplicable.

Pursuant to Form 10-K's General Instruction ("General Instruction") G(3), the following Information Is included as an additional item in Part 1:

19

• 0*

Executive Officers of the Registrant Age at December Effective Executive Officer 31, 1991 Comoany Position Date John E. Bryson 48 Chairman of the Board, Chief Executive October 1, 1990 Officer and Director(1)

Michael R. Peevey 53 President and Director(1)

October 1, 1990 David N. Barry III 64 Vice President and General Counsel March 1, 1989 Richard K Bushey 51 Vice President and Controller July 21, 1988 Alan J. Fohrer 41 Vice President, Treasurer and April 1, 1991 Chief Financial Officer Diana L Peterson-More 41 Corporate Secretary March 6, 1989 (1) Messrs. Bryson and Peevey hold the same positions with Edison, effective October 1, 1990. SCEcorp is the parent holding company of Edison.

None of SCEcorp's executive officers are related to each other by blood or marriage. As set forth in Article IV of SCEcorp's Bylaws, the officers of.SCEcorp are chosen annually by and serve at the pleasure of SCEcorp's Board of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected. Each of the executive officers of SCEcorp holds an identical position with Edison and has been actively engaged in the business of Edison for more than five years. Those officers who have not held their present position with SCEcorp and/or Edison for the past five years had the following business experience during that period:

John E. Bryson Executive Vice President and May 1988 to Chief Financial Officer of SCEcorp September 1990 Executive Vice President and January 1985 to Chief Financial Officer of Edison September 1990 Michael R. Peevey Executive Vice President of SCEcorp May 1988 to September 1990 Executive Vice President of Edison January 1986 to September 1990 David N. Barry III Associate General Counsel of Edison January 1982 to February 1989 Alan J. Fohrer Assistant Treasurer of SCEcorp July 1988 to March 1991 Assistant Treasurer and Manager of Cost September 1987 Control of Edison to March 1991 Manager, Corporate Planning and October 1986 to Budgeting of Edison August 1987 Diana L. Peterson-More Manager, Provider Services of Edison October 1987 to March 1989 Manager, Employee Services of Edison May 1984 to September 1987 20

PART 11 Item 5. Market for Registrant's Common Equity and Related Stockholder Matters Information responding to Item 5 is included in SCEcorp's Annual Report to Shareholders for the year ended December 31, 1991, ("Annual Report") under "Quartely Financial Data" on page 58 and under "Shareholder Information" on page 58, and Is Incorporated by reference pursuant to General Instruction G(2). The number of Common Stock shareholders of record was 138,404 on March 5, 1992. Additional information concerning the market for SCEcorp's Common Stock is set forth on the cover page hereof.

Item 6. Selected Financial Data Information responding to Item 6 Is Included in the Annual Report under "Selected Financial Data: 1987 1991" on page 56, and Is incorporated herein by reference pursuant to General instruction G(2).

Item 7. Management's Discussion and-Analysis of Results of Operations and Financial Condition Information responding to Item 7 is included in the Annual Report under "Management's Discussion and Analysis" on pages 33 through 41 and is Incorporated herein by reference pursuant to General Instruction G(2).

Item 8. Financial Statements and Supplementary Data Certain information responding to Item 8 is set forth after Item 14 in Part IV. Other information responding to Item 8 is included in the Annual Report on pages 35 through 57 and is Incorporated herein by reference pursuant to General Instruction G(2).

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.

PART III Item 10. Directors and Executive Officers of the Registrant Information concerning executive officers of SCEcorp is set forth in Part I in accordance with General Instruction G(3), pursuant to Instruction 3 to Item 401(b) of Regulation S-K. Other Information responding to Item 10 is included in the Joint Proxy Statement ("Proxy Statement") filed with the Commission in connection with SCEcorp's Annual Meeting to be held on April 16, 1992, under the heading, "Election of Directors of SCEcorp and Edison," and is incorporated herein by reference pursuant to General Instruction G (3).

Item 11. Executive Compensation Information responding to Item 11 is included in the Proxy Statement under the heading "Election of Directors of SCEcorp and Edison," and is Incorporated herein by reference pursuant to General Instruction G(3).

Item 12. Security Ownership of Certain Beneficial Owners and Management Information responding to Item 12 is included in the Proxy Statement under the heading "Election of Directors of SCEcorp and Edison," and is incorporated herein by reference pursuant to General Instruction G(3).

21

Item 13. Certain Relationships and Related Transactions Information responding to Item 13 is included In the Proxy Statement under the heading "Election of Directors of SCEcorp and Edison," and is Incorporated herein by reference pursuant to General Instruction G(3).

PART IV Item 14.

Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a)(1) Financial Statements The following items contained In the 1991 Annual Report to Shareholders are incorporated by reference in this report.

Management's Discussion and Analysis of Results of Operations and Financial Condition Responsibility for Financial Reporting Report of Independent Public Accountants Consolidated Statements of Income -

Years Ended December 31, 1991, 1990 and 1989 Consolidated Balance Sheets - December 31, 1991, and 1990 Consolidated Statements of Cash Flows - Years Ended December 31, 1991, 1990 and 1989 Consolidated Statements of Retained Earnings - Years Ended December 31, 1991, 1990 and 1989 Notes to Consolidated Financial Statements (2) Report of Independent Public Accountants and Schedules Supplementing Financial Statements The following documents may be found in this report at the Indicated page numbers.

Report of Independent Public Accountants on Supplemental Schedules.................

24 Schedule III

-Condensed Financial Information of Parent........................

25 Schedule V

-Property, Plant and Equipment for the Years Ended December 31, 1991, 1990Oand 1989.......................................

27 Schedule VI

-Accumulated Depreciation and Amortization of Property, Plant, and Equipment for the Years Ended December 31, 1991, 1990 and 1989.......

30 Schedule ViI

-Guarantees of Securities of Other Issuers for the Year Ended December 31, 1991..............................

33 Schedule ViII -Valuation and Qualifying counts for the Years Ended December 31, 1991, 1990 and 1989......................................34 Schedule IX -Short-Term Borrowings For Each of the Three Years in the Period Ended December 31, 1991.....

b 3

1 190. a....... 9.....

.37 Schedule X

-Supplementary Income Statement Information For Each of the Three Years in the Period Ended December 31, 1991..................38 Schedule XIII -Other Investments, December 31, 1991, and 1990....................39 Schedules I through XIII, inclusive, except those referred to above, are omitted as not required or not applicable.

(3) Exhibits See Exhibit Index on page 43 of this report.

22

(b) Reports on Form 8-K November 20, 1991 Item 5: Other Events: General Rate Case November 22, 1991 Item 5: Other Events: General Rate Case December 20, 1991 Item 5: Other Events: General Rate Case Additional Matter For the purpose of complying with the amendments effective July 13, 1990, to the rules governing registration statements on Form S-8 under the Securities Act of 1933, SCEcorp hereby undertakes as follows (which undertaking shall be incorporated by reference Into SCEcorp's Registration Statement on Form S-8 No. 33-32302, filed November 29, 1989):

Insofar as indemnification for liabilities arising under the Securities Act of 1933 may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Act and will be governed by the final adjudication of such issue.

23

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SUPPLEMENTAL SCHEDULES To SCEcorp:

We have audited, in accordance with generally accepted auditing standards, the consolidated financial statements included in the 1991 Annual Report to Shareholders of SCEcorp, Incorporated by reference in this Form 10-K, and have issued our report thereon dated February 7, 1992. Our audits of the consolidated financial statements were made for the purpose of forming an opinion on those basic consolidated financial statements taken as a whole. The supplemental schedules listed in Part IV of this Form 10-K which are the responsibility of SCEcorp's management are presented for purposes of complying with the Securities and Exchange Commission's rules and regulations, and are not part of the basic consolidated financial statements. These supplemental schedules have been subjected to the auditing procedures applied in the audits of the basic consolidated financial statements and, in our opinion, fairly state in all material respects the financial data required to be set forth therein in relation to the basic consolidated financial statements taken as a whole.

ARTHUR ANDERSEN & CO.

Los Angeles, California February 7, 1992 24

SCEcorp SCHEDULE III -

CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED BALANCE SHEETS December 31, 1991 1990 (In thousands)

Assets:

Cash and equivalents....................................

70,589 1,155 Other current assets.....................................

156,443 144,703 Total current assets....................................

227,032 145,858 Investments in subsidiaries................................

5,609,852 5,500,331 Other assets...........................................

869 1.364 Total assets

$ 5.837.753

$5,647,553 Liabilities and Shareholders' Equity:

Accounts payable........................................

35,052 1,111 Other current liabilities...................................

122,417 144,193 Total current liabilities..................................

.157,469 145,304 Deferred taxes..........................................

(599)

(401)

Common shareholders' equity.............................

5,68,8 5,502,650 Total liabilities and shareholders' equity.....................

$ 5837.753

$ 5.647.553 CONDENSED STATEMENTS OF INCOME For the Years Ended December 31, 1991, 1990, and 1989 1991 1990 1989 (In thousands, except per-share amounts)

Operating revenue and Interest income................

$ 8,662

$ 10,881

$ 7,957 Operating expenses and income taxes................

9,454 11,162 8,251 Loss before equity in earnings of subsidiaries..........

(792)

(281)

(294)

Equity in earnings of subsidiaries......................

703,397 786,641 778,535 Net income............................

$702605

$786,360

$778241 Weighted-average shares of common stock outstanding....

218,660 218,474 218,463 Earnings per share...............................

.21....

60

$3.56 25

SCEcorp SCHEDULE II--CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)

CONDENSED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1991, 1990, and 1989 1991 1990 1989 (In thousands)

Cash Flows From Operating Activities.................

(71) 106 Cash Flows From Financing Activities:

Capital contributions............................

69,505 Cash Flows From Investing Activities..................

(111)

Increase (Decrease) in cash and equivalents.............

69,434 106 (577)

Cash and equivalents at beginning of period.............

1,155 1,Q49 1,626 Cash and Equivalents at the End of Period............

$ 70.589

$ 1,155

$ 1.049 Cash dividends received from Southern California Edison Company..............................

$588513

$643033

$680524 26

SCEcorp SCHEDULE V -

PROPERTY, PLANT AND EQUIPMENT For the Year Ended December 31, 1991 Balance at Add (Deduct)

Balance Beginning of Additions Other at End of Description Period at Cost Retirements Chanaes Period (In thousands)

Steam production...........

.$ 1,960,914 98,818 (5,328)

$ 2,054,404 Nuclear production...........

.5,789,475 129,931 (3,534) 5,915,872 Hydro production............

556,197 13,555 (373)

(57) 569,322 Other production...........

395,963 5,039 (6,367) 394,635 Transmission..............

2,405,526 74,072 (11,120) 2,468,478 Distribution.................

4,961,068 393,032 (61,807)

(388) 5,291,905 General...................

920,813 97,158 (21,714)

(2,266) 993,991 Plant held for future use.......

17,110 152 (21) 388 17,629 Experimental electric plant unclassified.............

30,314 27,831 58,145 Other utility plant...............

7,224 506

3) 7,692 Subtotal-utility plant........17,044,604 840,094 (110,302)

(2,323) 17,772,073 Construction work in progress.............

741,040 39,471(a) 13,792 794,303 Nuclear fuel................

1,020,897 83.674 (131,017) 973,554 Gross utility plant..........$18806,541

$ 963.239

$(227.527)

$(2.323

$19.539,930 Nonutility property.......... $

144,648 19,731

$ (11.291)

$13027 166.115 (a)

Reflects transfers to plant in service, which are net of additions to construction work In progress.

27

SCEcorp SCHEDULE V -

PROPERTY, PLANT AND EQUIPMENT For the Year Ended December 31, 1990 Balance at Add (Deduct)

Balance Beginning of Additions Other at End of Description Period at Cost Retirements Changes Period (In thousands)

Steam production............$ 1,924,147 44,447 (5,077)

$(2,603)

$ 1,960,914 Nuclear production...........5,719,716 71,514 (1,691)

(64) 5,789,475 Hydro production...........

546,074 10,404 (1,123) 842 556,197 Other production...........

391,114 5,224 (375) 395,963 Transmission..............

2,316,349 106,410 (17,621) 388 2,405,526 Distribution.................

.4,652,696 362,296 (53,536)

(388) 4,961,068 General..................

829,142 92,863 (9,242) 8,050 920,813 Plant held for future use......

17,659 780 (1,329) 17,110 Experimental electric plant unclassified.............

35,517 2,525 (229)

(7,499) 30,314 Other utility plant...........

7,062 175 (13)

-7224 Subtotal-utility plant........16,439,476 696,638 (88,907)

(2,603) 17,044,604 Construction work In progress................

593,760 161,670(a)

(16,993) 2,603 741,040 Nuclear fuel................

1,052,295 37,334 (68,732) 1,020.897 Gross utility plant..........$18085.531 895,642

$(174.632)

L

$18,806,541 Nonutility property.......... $

133,077 S

.742

$ (18258)

$1 144.648 (a)

Reflects transfers to plant in service, which are net of additions to construction work In progress.

28

SCEcorp SCHEDULE V -

PROPERTY, PLANT AND EQUIPMENT For the Year Ended December 31, 1989 Balance at Add (Deduct)

Balance Beginning of Additions Other at End Description Period at Cost Retirements Chanaes of Period (in thousands)

Steam production...........

.$ 1,892,736

$ 42,438

$ (11,027)

$ 1,924,147 Nuclear production..........

5,658,708 72,779 (8,059)

(3,712) 5,719,716 Hydro production...........

532,005 15,867 (350)

(1,448) 546,074 Other production............

392,616 1,547 (1,231)

(1,818) 391,114 Transmission..............

2,132,616 186,988 (8,097) 4,842 2,316,349 Distribution................

4,263,950 444,250 (53,218)

(2,286) 4,652,696 General...................

771,545 77,858 (23,310) 3,049 829,142 Plant held for future use......

19,481 1,170 (2,992) 17,659 Experimental electric plant unclassified.............

17,126 18,391 35,517 Other utility plant...........

7,0673

)

7,062 Subtotal-utility plant........15,687,850 861,291 (108,292)

(1,373) 16,439,476 Construction work in progress..............

676,175 (81,335)(a)

(1,080) 593,760 Nuclear fuel...............

1,046,090 47,555 (41350) 1,052,295 Gross utility plant..........$17410,115

$ 827.511

$(50,722

$ (1.373

$18,085,531 Nonutility property...........

130.421.

$ 14,155 (8,965)

$ (2.534 133,077 (a) Reflects transfers to plant in service, which are net of additions to construction work in progress.

29

SCEcorp SCHEDULE VI -

ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT For the Year Ended December 31, 1991 Additions Charged Balance at to Costs Add (Deduct)

Balance Beginning of and Other at End of Description Period Expenses Retirements Charges(a)

Salvaae Period (In thousands)

Steam production......$1,217,709

$ 88,644 (5,112)

(778) 550

$1,301,013 Nuclear production....

1,607,984 324,610 (3,508)

(3,050) 52 1,926,088 Hydro production.....

135,630 8,754 (387)

(240) 40 143,797 Other production.....

222,660 12,554 (6,365)

(109) 228,740 Transmission........

724,070 76,608 (10,686)

(2,606) 3,291 790,677 Distribution..........

1,601,611 190,922 (61,709)

(27,789) 9,540 1,712,575 General............

219,110 51,831 (21,809) 4,981 422 254,535 Experimental electric plant unclassified...

11,003 8,272 19,275 Retirement work in....

progress..........

(46,557) 14,426 (8,239)

(220)

(40,590)

Other utility plant reserves..........

2,863 213 (3) 1

-3,0 Subtotal............5,696,083 762,408 (95,189)

(37,829) 13,675 6,339,148 Nuclear fuel amortization.......

725,989 131,355 (131,017) 726.327 Total utility plant reserves..........

$6.422.072

$893763

$ (226,206)

$(37829)

$13,675

$7,065,475 Nonutility property reserves..........

36021 5489 (2,504)

$ (1846 37.160 (a)

Includes removal costs related to facilities retired, damage claims and relocation costs collected from others, and various other adjustments of depreciation and amortization.

30

SCEcorp SCHEDULE VI-ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT For the Year Ended December 31, 1990 Additions Charged Balance at to Costs Add (Deduct)

Balance Beginning of and Other at End of Description Period Expenses Retirements Charaes(a)

Salvaae Period (In thousands)

Steam production......$1,137,435

$ 85,384 (5,080)

(31) 1

$1,217,709 Nuclear production....

1,302,766 304,422 (1,787) 2,472 111 1,607,984 Hydro production.....

128,554 8,480 (1,074)

(333) 3 135,630 Other production.....

210,787 12,246 (375)

(13) 15 222,660 Transmission........

667,710 71,812 (18,925)

(551) 4,024 724,070 Distribution...........

1,490,859 179,470 (53,979)

(23,048) 8,309 1,601,611 General............

179,187 45,721 (8,608) 2,292 518 219,110 Experimental electric plant unclassified...

5,407 7,201 (229)

(1,376) 11,003 Retirement work in progress...........

(30,294)

(19,387) 4,560 (1,436)

(46,557)

Other utility plant reserves..........

2675 203 (14)

(1 2,863 Subtotal..........

5,095,086 714,939 (109,458)

(16,029) 11,545 5,696,083 Nuclear fuel amortization.......

658,171 136,550 (68,732) 725.989 Total utility plant reserves........

$5,753,257

$851489

$ (178.190)

$0602

$11,545

$6,422,072 Nonutility property reserves..........

36,017

$543 (4,678)

$ (750

$ 36021 (a) Includes removal costs related to facilities retired, damage claims and relocation costs collected from others, and various other adjustments of depreciation and amortization.

31

SCEcorp SCHEDULE VI-ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT For the Year Ended December 31, 1989 Additions Charged Balance at to Costs Add (Deduct)

Balance Beginning of and Other at End Description Period Expenses Retirements Changes(a) Salvage of Period (In thousands)

Steam production....

$ 1,066,854 $ 85,235

$ (13,292)

$ (1,382) 20

$ 1,137,435 Nuclear production...

1,011,206 302,973 (7,962)

(3,555) 104 1,302,766 Hydro production....

120,614 8,293 (337)

(16) 128,554 Other production....

199,137 12,422 (785) 13 210,787 Transmission.......

603,899 70,085 (5,218)

(3,062) 2,006 667,710 Distribution..........1,391,040 165,843 (53,271)

(26,372) 13,619 1,490,859 General...........

160,332 40,949 (23,431)

(629) 1,966 179,187 Experimental electric plant unclassified 1,313 4,125 17,325 (17,356) 5,407 Retirement work in progress...........

(26,935)

(6,326) 5,602 (2,635)

(30,294)

Other utility plant reserves.........

2,478 199 (2) 2,675 Subtotal..........

4,529,938 690,124 (93,299)

(46,770) 15,093 5,095,086 Nuclear fuel amortization......

570,326 129,195 (41,350) 658,171 Total utility plant reserves.......

$5,100,264

$5819319 $(134.64)

$4.7

$15,093

$5,753,257 Nonutility property reserves.......... ;_

22,570 3.483 (7.203)

$ 17167 36.017 (a) Includes removal costs related to facilities retired, damage claims and relocation costs collected from others, and various other adjustments of depreciation and amortization.

32

SCEcorp SCHEDULE VII -

GUARANTEES OF SECURITIES OF OTHER ISSUERS For the Year Ended December 31, 1991 (In Thousands)

Nature of any default Arnount in by Issuer of securities Name of Issuer Tille of issue teasury of guaranteed In principal, of securities of each class Total amount iauer of interest, snldng fund guaranteed by of securities guarantsed and Anount owned securities Nature of redernption provisions, SCEcrp nuaratleed ousanding by Compa nt or payment of dividends Ontario Lakeshore Construction Principal Partners Loan

$ 4,700 and Interest None Parkway Construction Business Loan Principal Centre Partners

$10,000 and Interest None Mission-DAII Construction Principal Loan

$ 4,200 and Interest None 33

SCEcorp SCHEDULE VIII -

VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 1991 Additions Balance at Charged to Charged to Balance Beginning of Costs and Other at End Description Period Expenses Accounts Deductions of Period (In thousands)

Group A:

Uncollectible accounts Customers............

$ 10,423

$ 22,529

$22,924

$ 10,028 All other.............

7,814 2,358 5

4,934 Total................

$ 18(237

$ 24,887

$28,162$a) 14962 Group B:

Regulatory settlement

$ 124,000(b)

$124,000 Environmental cleanup.-

40,000(c) 40,000 Pension and benefits........

98,886 29,267 18,749(d) 34,895(e) 112,007 Insurance, casualty and other................

61 620 63,901 55008(f) 70.513 Total...............

$W0

$ 217.168

$58,749

$89,903

$346,520 (a) Accounts written off, net.

(b) Represents a reserve addition for a proposed settlement with the California Public Utilities Commission's Division of Ratepayer Advocates regarding affiliated company power purchases.

(c)

Represents an estimated minimum liability established for environmental cleanup costs expected to be incurred and recovered through rates in future years.

(d) Primarily represents transfers from the accrued paid absence allowance account for required additions to the comprehensive disability plan accounts.

(e) Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.

(f) Amounts charged to operations that were not covered by Insurance.

34

SCEcorp SCHEDULE VIII -

VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 1990 Additions Balance at Charged to Charged to Balance Beginning of Costs and Other at End Description Period Expenses Accounts Deductions of Period (In thousands)

Group A:

Uncollectible accounts Customers............

$ 6,804

$20,660

$17,041

$ 10,423 All other 3..............

7280-7,814 Total................

$ 14.084

$24388

$20235(a)

$18.237 Group B:

Pension and benefits........

$ 94,729

$21,800

$18,494(b)

$36,137(c)

$ 98,886 Insurance, casualty and other................

60090 49234 AZ70(d) 61,620 Total...............

V54,819

$71.034

$1844

$83841

$160506 (a) Accounts written off, net.

(b) Primarily represents transfers from the accrued paid absence allowance account for required additions to the comprehensive disability plan accounts.

(c)

Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.

(d) Amounts charged to operations that were not covered by Insurance.

35

SCEcorp SCHEDULE Vill -

VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 1989 Additions Balance at Charged to Charged to Balance Beginning of Costs and Other at End Description Period Expenses Accounts Deductions ofPeriod (In thousands)

Group A:

Uncollectible accounts Customers............

$ 7,114

$14,700

$15,010

$ 6,804 All other 6,073 32027280 Total................

$ 13,187

$19,109

$18,212(a)

$ 14.084 Group B:

Pension and benefits.......

$ 80,515

$21,367

$18,474(b)

$25,627(c)

$ 94,729 Insurance, casualty and other................

56,295 4 12

_2--(d) 60,090 Total................

$136810

$67,495

$18474

$154819 (a) Accounts written off, net.

(b) Primarily represents transfers from the accrued paid absence allowance account for required additions to the comprehensive disability plan accounts.

(c)

Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.

(d) Amounts charged to operations that were not covered by insurance.

36

SCEcorp SCHEDULE IX -

SHORT-TERM BORROWINGS For Each of the Three Years In the Period Ended December 31, 1991 Weighted Maximum Average Average Weighted Amount Amount Interest Balance Average Outstanding Outstanding Rate at End Interest During During During Description of Period Rate the Period the Period the Period (a)

(b)

(Dollars in thousands)

December 31, 1991:

Payable to holders of commercial paper-general purpose......

$ 461,900

$ 149,633 6.39%

Payable to holders of commercial paper-balancing accounts....

$ 419,600 5.14%

506,700 476,000 6.36 Payable to holders of commercial paper-fuel................

372,200(c) 5.14 436,100 397,000 6.36 Payable to bank-leveraged leases 181,600(c) 4.95 186,600 94,133 7.78 Payable to bank--general purpose..................

121,310 5.58 214,785 85,614 7.28 Payable to unconsolidated subsidiary-fuel..............

16,000 5.57 16,000 3,995 6.10 December 31, 1990:

Payable to holders of commercial paper-general purpose......

$ 461,596 8.29%

$461,596

$ 121,517 8.44%

Payable to holders of commercial paper-balancing accounts....

506,700 8.25 537,500 507,800 8.33 Payable to holders of commercial paper-fuel................

436,100(c) 8.25 520,700 432,800 8.33 Payable to holders of commercial paper-leveraged leases......

140,911(c) 8.65 140,911 123,850 8.78 Payable to bank-general.

purpose..................

45,000 9.02 89,400 45,836 8.91 Payable to others-fuel.........

200,000 39,726 8.02 December 31, 1989:

Payable to holders of commercial paper-general purpose......

$ 10,700 8.72%

$ 74,600

$ 11,000 9.30%

Payable to holders of commercial paper-balancing accounts....

501,600 8.72 501,600 393,900 9.30 Payable to holders of commercial paper-fuel................

281,600(c) 8.72

.535,300 335,200 9.30 Payable to holders of commercial paper-leveraged leases.......

99,000(c) 8.60 99,000 99,000 9.33 Payable to bank-general purpose..................

78,500 9.62 91,000 32,142 9.63 Payable to others-fuel..........200,000(c) 8.42 200,000 160,274 8.88 (a) Average amount outstanding during the period is computed by dividing the total of daily outstanding principal balances by 365.

(b) Weighted-average interest rate during the period is computed by dividing the total Interest expense by the average amount outstanding.

(c) Under credit agreements with commercial banks which allow SCEcorp to refinance short-term borrowings on a long-term basis, borrowings of $332,600,000 as of December 31, 1991, and

$268,600,000 as of December 31, 1990, ($371,600,000 as of December 31, 1989), have been reclassified as long-term debt on the Consolidated Balance Sheet In the 1991 Annual Report to reflect the anticipated timing of repayment payments of nuclear fuel indebtedness.

37

SCEcorp SCHEDULE X -

SUPPLEMENTARY INCOME STATEMENT INFORMATION For Each of the Three Years in the Period Ended December 31, 1991 Charged to Expense (In thousands)

Year ended December 31, 1991:

Property taxes.....................

$151,869 Year ended December 31, 1990:

Property taxes....................................................

132,636 Year ended December 31, 1989:

Property taxes...................................................

.138,344 Note:

Depreciation and maintenance expenses appear on the Consolidated Statements of Income.

Royalties paid and advertising costs included In Other Operating Expenses are less than 1% of total operating revenue.

38

SCEcorp SCHEDULE XIII -

OTHER INVESTMENTS December 31, 1991 (In thousands)

Number of shares Amount at which or principal Market carried in balance Description amount Cost value sheet Investments in nuclear decommissioning trusts:

Qualified trust................

$ 438,226 $ 455,960

$ 438,226 Non-qualified trust...........

77,641 89,796 77,641

$ 515.867 $ 545,756

$ 515867 Investments in partnerships and unconsolidated subsidiaries:

Energy partnerships.-

$ 771,588 $ 820,557

$ 820,320 Real estate partnerships.-

285,817 278,817 270,549 Unconsolidated subsidiary...

207,756 205,209 205,209

$1.265,161

$1.304.583

$1,296.078 Investments in leveraged leases(a).$

319684 $ 319,684

$ 382.256 Other investments................

$ 46,273 $

46273 46273 (a) Market value is assumed to equal current unrecovered Investment less deferred taxes.

39

SCEcorp SCHEDULE XIII -

OTHER INVESTMENTS December 31, 1990 (In thousands)

Number of shares Amount at which or principal Market carried in balance Description amount Cost value sheet Investments in nuclear decommissioning trusts:

Qualified trust...............

$323,745 $ 333,493

$ 323,745 Non-qualified trust...........

60,922 64,870 60.922

$384,667 $ 398,363

$ 384.667 Investments in partnerships and unconsolidated subsidiaries:

Energy partnerships..-

$679,906 $ 717,709

$ 717,709 Real estate partnerships.-

155,917 195,907 182,366 Unconsolidated subsidiary.....

120,350 121,427 121,427

$956,173

$1,035,043

$1,021,502 Investments in leveraged leases(a)

$,24291

$ 151,786

$ 316.120 Other investments...............

$ 62,240 62240 62,240 (a) Market value is assumed to equal current unrecovered Investment less deferred taxes.

40

SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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.

SCEcorp By ALAN J. FOHRER (Alan J. Fohrer, Vice President, Treasurer and Chief Financial Officer)

Date: March 19, 1992 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates Indicated.

Siqnature Title Date Principal Executive Officer:

John E. Bryson*.

Chairman of the Board, March 19, 1992 Chief Executive Officer and Director Principal Financial Officer:

Alan J. Fohrer*

Vice President, Treasurer March 19, 1992 and Chief Financial Officer Controller or Principal Accounting Officer:

Richard K. Bushey*

Vice President and March 19,1992 Controller Majority of Board of Directors:

Howard P. Allen*

Director March 19,1992 Roy A. Anderson*

Director March 19,1992 Norman Barker, Jr.*

Director March 19, 1992 Warren Christopher*

Director March 19, 1992 Camilla C. Frost*

Director March 19,1992 Walter B. Gerken*

Director March 19,1992 William R. Gould*

Director March 19,1992 Joan C. Hanley*

Director March 19,1992 Carl F. Huntsinger*

Director March 19, 1992 Charles D. Miller*

Director March 19, 1992 Michael R. Peevey*

Director March 19, 1992 J. J. Pinola*

Director March 19, 1992 James M. Rosser*

Director March 19,1992 Henry T. Segerstrom*

Director March 19, 1992 E. L Shannon, Jr.*

Director March 19,1992 Robert H. Smith*

Director March 19, 1992 Edward Zapanta*

Director March 19, 1992

• By ALAN J. FOHRER (Alan J. Fohrer, Attorney-in-Fact) 41

CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our report dated February 7, 1992, (the Report of Independent Public Accountants) appearing on page 57 of the 1991 Annual Report to Shareholders of SCEcorp (Exhibit 13 Included herein) In this Annual Report on Form 10-K for the year ended December 31, 1991 of SCEcorp. It should be noted that we have not audited any financial statements of SCEcorp subsequent to December 31, 1991 or performed any audit procedures subsequent to the date of our report.

We further consent to the Incorporation by reference of the above-mentioned Report of Independent Public Accountants, incorporated by reference in this Annual Report on Form 1 0-K, and to the incorporation by reference of our report (the Report of Independent Public Accountants on Supplemental Schedules),

appearing on page 24 of this Annual Report on Form 10-K, in the Registration Statements which follow:

Entity Reqistration Form File No.

Effective Date SCEcorp Form S-3 33-44148 December 2, 1991 SCEcorp Form S-3 33-42062 August 27, 1991 SCEcorp Form S-8 33-37381 October 19, 1990 SCEcorp Form S-8 33-32302 December 19, 1989 ARTHUR ANDERSEN & CO.

Los Angeles, California March 19, 1992 42