ML13330A319
| ML13330A319 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 05/01/1981 |
| From: | Hughes W Southern California Edison Co |
| To: | Saltzman J Office of Nuclear Reactor Regulation |
| References | |
| NUDOCS 8105060326 | |
| Download: ML13330A319 (40) | |
Text
Southern California Edison Company P. 0.
BOX 800 2244WALNUTGROVEAVENUE ROSEMEAD. CALIFORNIA 91770 W. G. HUGHES, JR.
TELEPHONE MANAGER OF INSURANCE May 1, 1981 (213) 572-1079 O)
Mr. Jerome Saltzman I
t$
Chief, Antitrust & Indemnity Group Nuclear Reactor Regulation Nuclear Regulatory Commission Washington, D.C. 20555 U.S. NUCLEAR REGULOIY Re:
Docket No. 50-206
Dear Mr. Saltzman:
In compliance with Section 140.21 of 10 CFR Part 140, the following materials are submitted on behalf of Southern California Edison Company and San Diego Gas & Electric Company, as 80% -
20% owners of San Onofre Nuclear Generating Station Unit 1:
- 1. One copy of Annual Report to the Securities and Exchange Commission (Form 10-K) for the fiscal year ended December 31, 1980.
- 2. Cash Flow Statement for the fiscal year ended December 31, 1980.
Since ly, WGH:JR Enclosures cc:
Messrs. H. Fred Christie Michael L. Noel D. N. Barry III Craig Hubble
.5 01/
SOUTHERN CALIFORNIA EDISON COMPANY 1981 Internal Cash Flow Projection for San Onofre Nuclear Generating Station Unit 1 (Dollars in Thousands) 1980 1981 Actual Projected Net Income After Taxes
$317,536 Less Dividends Paid 273,312 Retained Earnings
$ 44,224 Adjustments:
Depreciation & Amortization
$187,959
$204,000 Deferred Investment Tax Credits 25,235 34,000 Allowance for Funds Used During Construction (162,287)
(230,000)
Total Adjustments
$ 50,907 8,000 Internal Cash Flow
$ 95,131 Average Quarterly Cash Flow
$ 23,783 Percentage Ownership Unit #1 80%
Southern California in All Operating Edison Company Nuclear Units 20%
San Diego Gas &
Electric Company Maximum Total Contingent Liability
$ 10,000 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 1981 is expected to be comparable to the Actual Cash Flow for 1980.
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TABLE OF CONTENTS Part I Item I.
Business Pg
- 2. Properties 7
- 3. Legal Proceedings 7
- 4. Security Ownership of Certain Beneficial Owners and Management 12 Part II
- 5. Market for the Registrant's Common Stock and Related Security Holder Matters 20
- 6. Selected Financial Data.................
......... 2 20
- 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.......
.. 2
- 8. Financial Statements and Supplementary Data 20 Part Ill
- 9. Directors and Executive Officers of the Registrant 20
- 10.
Management Remuneration and Transactions 20 Part IV
- 11.
Exhibits, Financial Statement Schedules and Reports on Form 8-K...........20 Schedules Supporting Financial Statement s and Reports 22 Signatures
.33 Exhibit Index and Exhibits.
35
PART I Item 1. Business Southern California Edison Company ("Company") was incorporated in 1909 under Cali fornia 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 eight million people. As of December 31, 1980, the Company had 14,157 employees.
General problems of the industry The electric utility industry in general is currently experiencing problems relating to (i) high costs of fuel, wages and materials, (ii) vast capital outlays and longer construction periods for the larger and more complex new generating units needed to meet current and future service requirements of customers, (iii) increasing levels of allowance for funds used during construction ("AFUDC"), which are non-cash earnings, resulting from such capital outlays and longer construction periods, (iv) greater reliance on capital markets with high costs of both equity and borrowed capital, (v) effects of compliance with numerous regulatory and environmental requirements, and (vi) difficulties and delays in obtaining needed rate increases. The Company is, to varying degrees, currently experiencing all of these problems.
Regulation The retail operations of the Company are subject to regulation by the California Public Utilities Commission ("CPUC"), which has the authority to regulate, among other things, retail rates, issuances of securities and accounting and depreciation practices. The Company's resale operations are subject to regulation by the Federal Energy Regulatory Commission
("FERC") as to rates on sales for resale, as well as other matters, including accounting and depreciation practices.
The Company is subject to the jurisdiction of the Nuclear Regulatory Commission (."NRC")
with respect to nuclear power plants. NRC regulations govern the granting of licenses for the construction and operation of nuclear power plants and subject such power plants to continuing review and regulation.
The Company's plant construction, planning and siting are subject to the jurisdiction of the California Energy Commission. The Company is subject to rules and regulations promul gated by the California Air Resources Board and local air pollution control districts with respect to the emission of pollutants into the atmosphere, and the regulatory requirements of the California Water Resources Control Board and regional boards with respect to the dis charge of pollutants into waters of the state. The Company is also subject to regulation by the Environmental Protection Agency ("EPA"), which administers certain federal statutes relating to environmental matters, and to certain other federal, state and local laws and regulations relating to environmental protection and land use.
The Department of Energy has regulatory authority over certain aspects of energy con servation, solar energy development, power plant fuel use, coal conversion, public utility regulatory policy and natural gas pricing.
RATE MATTERS Retail rates In December 1979, the Company filed with the CPUC a general rate application designed to increase annual revenues by approximately $340,000,000 based on a 1981 test year which, under various assumptions made at the date of filing, would have afforded the Company a 1
reasonable opportunity to earn an average rate of return on common equity of 15% for the 1981-82 period. On December 30, 1980, the CPUC issued a general rate decision which authorized new rates effective January 1, 1981 designed to increase the Company's revenues by approximately $294,000,000 annually. The CPUC decision also authorized a general rate increase effective January 1, 1982 designed to-produce additional annual revenues of approxi mately $92,000,000 to offset higher operating and capital costs expected to be incurred in 1982. The CPUC decision is designed to enable the Company to earn a 14.95% rate of return on common equity. The decision also provides that, should actual base rate revenues exceed authorized base rate revenues, the excess revenues will be subject to refund. Under present CPUC procedures, applications for general rate relief are filed at two-year intervals.
Energy cost adjustment clause The Company's Energy Cost Adjustment Clause ("ECAC") provides for adjustments in rates, subject to CPUC approval, to reflect changes in energy costs. Under the ECAC pro cedure, changes in those energy costs which are subject to ECAC should not affect the Company's reported earnings because such costs are reported as operating expenses only as they are reflected in electric rates and thereby offset by revenues. An ECAC balancing account has been established in which energy costs above or below those used in establishing rates are accumulated, and the accumulated amount is reflected in succeeding rate adjustments.
Effective May 20, 1980, the CPUC authorized an increase in the Company's revenues under ECAC of approximately $560,000,000 on an annual basis. As a result, ECAC under collections experienced in 1978 and 1979, together with interest, were fully recovered in 1980.
On December 31, 1980, the balance in the ECAC balancing account, representing net over collections and accrued interest, was $38,076,000.
On October 8, 1980, the CPUC issued an interim decision approving a Company filing providing for a reduction in revenues under the ECAC of approximately $236,300,000 on an annual basis, including recovery of $35,000,000 in the ECAC balancing account which had been deferred by an earlier CPUC decision. A final decision regarding recovery of the $35,000,000 has not yet been rendered. On December 30, 1980, the CPUC approved a further annual reduction in ECAC revenues of approximately $194,000,000.
On December 5, 1980, the CPUC modified energy cost adjustment procedures for Cali fornia utilities. In addition to various procedural changes, the revised ECAC procedures will provide for the application of ECAC to 98% of the Company's energy costs. In accordance with the modified procedure, the Company has proposed to the CPUC the establishment of a new rate component, to be adjusted annually, called the Annual Energy Rate, designed to reflect estimated costs associated with (i) fuel oil inventory,, (ii) facility charges and underlift pay ments, (iii) the remaining 2% of the Company's energy costs, and (iv) gains or losses on the sale of fuel oil.
The Company has filed an application to revise base rates and ECAC rates effective May 1, 1981, in accordance with the new procedure. Base rates would be reduced by $90,200,000, ECAC rates would be reduced by $53,600,000 and the Annual Energy Rate would be established at an initial level of $270,500,000 for a net annualized increase of $126,700,000.
Resale rates Pursuant to FERC procedures, on August 4, 1974, February 1, 1976, and August 16, 1979, increases in the Company's resale rates became effective, subject to refund with interest to the extent that any of the increases are subsequently determined to be inappropriate.
An August 1, 1979 FERC decision affirmed the August 4, 1974 rate increase with respect to cost of service. The decision provided that the rate increase remain subject to refund 2
pending resolution of an anti-competitive "price squeeze" issue raised by intervenors. On May 23, 1980, the FERC Administrative Law Judge granted the Company's motion for summary disposition in the "price squeeze" proceedings relating to the August 4, 1974 rate increase.
The intervenors and the FERC staff have filed exceptions to the Administrative Law Judge's ruling with the FERC.
An August 22, 1979 FERC decision on the February 1, 1976 rate increase required the Company to file a revised cost of service which reduced the annual increase in revenues.
Revenues billed in excess of the revised cost of service had previously been deferred and the related interest accrued. Both the Company and certain intervenors petitioned for a rehearing which was denied on March 20, 1980 by the FERC. The August 22, 1979 decision also found that the Company's resale customers had established a prima facie case of a "price squeeze" and provided that the case would be remanded to an Administrative Law Judge for hearings to determine the extent of such "price squeeze," if any, with respect to the filed revised rates.
If a "price squeeze" is determined to exist, a further rate reduction may be imposed which could result in additional refunds. Both the Company and intervenors have filed petitions with the Court of Appeals for review of the August 22, 1979 decision.
As of December 31, 1980, approximately $473,100,000 had been billed subject to refund.
The Company believes that any amounts which the FERC may require the Company to refund as a result of the above proceedings should not have a material financial effect on the Company.
The FERC decisions could adversely affect the pending antitrust litigation instituted in federal district court on March 2, 1978 by five of the Company's resale customers (See "Anti trust litigation" under Item 3).
In December 1980, the Company filed an application with the FERC requesting an increase in resale rates designed to generate $18,600,000 in annual revenues which pursuant to a FERC order will be reduced to $16,700,000. The resultant increase is expected to become effective, subject to refund, on July 16, 1981. Additionally, the FERC accepted for filing a proposed adjustment in the resale rates which reflects the inclusion in rate base of San Onofre Unit 2.
The effective date for such rates, however, would be suspended until five months after the date of commercial operation.
FUEL SUPPLY Fuel and purchased power costs amounted to approximately $2 billion in 1980, 31%
higher than in 1979. Sources of energy and unit costs of fuel for 1976 through 1980 were as follows:
Sources of energy Average cost per million BTU's(1) 1976 1977 1978 1979 1980 1976 1977 1978 1979 1980 Oil............
47%
56%
43%
44%
28%
2520 2540 2910 3400 5310 Natural gas......11 15 18 23 30 125 185 205 239 333 Coal............
14 14 10 11 12 36 41 53 71 69 Nuclear........
3 3
3 4
1 29 34 36 43 82 All fuels......... 75 88 74 82 71 180 200 224 258 358 Hydroelectric...
4 2
9 8
9 (2)
(2)
(2)
(2)
(2)
Purchased and interchanged power..........21 10 17 10 20 (3) 100%
100%
100%
100%
100%
(1) British Thermal Unit ("BTU") -The standard unit of measure for the heat content of fuels.
It is the amount of heat required to raise the temperature of one pound of water, at 39.1 degrees Fahrenheit, by one degree Fahrenheit.
(Footnotes continued on following page) 3
(2) There are no fuel costs associated with the Company's hydroelectric generation.
(3) For the year ended December 31, 1980, the cost of purchased power was 2.252 cents per kilowatt-hour.
The prices for oil now under contract are subject to various adjustments based on, among other factors, specified foreign prices for crude oil (including prices established by OPEC nations), import license fees and duties, royalties, taxes and transportation charges.
Average fuel costs, expressed in cents per kilowatt-hour for the year ended December 31, 1980 were: oil 5.0810; natural gas 3.5060; coal 0.8040; and nuclear 0.8990. The per kilowatt-hour cost of nuclear fuel increased in 1980 from 1979 because of associated fixed costs being allocated to reduced generation of nuclear power in 1980.
Natural gas supply A number of the Company's major steam electric generating units are designed to burn oil or natural gas as a primary boiler fuel. Although increased supplies of natural gas have recently become available to the Company, the extent of the Company's use of natural gas as boiler fuel is dependent upon the amount of gas available from the Company's primary gas supplier as well as upon applicable federal and state laws and regulations. To the extent the Company's use of natural gas is restricted, it will be forced to rely more heavily on fuel oil, with resulting increases in fuel expenses.
Fuel oil supply Air pollution control laws and regulations applicable to the Company's oil-and gas-fired steam electric generating units have required the Company to depend to an increasing extent on more costly 0.25% low-sulphur fuel oil. Based upon current projections of gas availability, the Company now has under contract approximately 100% of its estimated requirements for 0.25% low-sulphur fuel oil through 1986. To the extent that oil demand in this period exceeds current forecasts, additional supplies are expected to be available from purchases made on the spot market, under short-term contracts or through flexibility in existing long-term contracts.
As of December 31, 1980, the Company had in inventory approximately 16,100,000 barrels of low-sulphur fuel oil which, depending on utilization of other fuel sources, will supply the Company's oil-burning facilities for at least 90 days. Because of the availability of other less expensive fuel and energy sources in 1980 and the resultant increase in fuel storage levels, the Company sold excess quantities of fuel oil and anticipates additional sales of excess fuel oil in 1981.
In addition, the Company was unable to take delivery of fuel oil and thereby incurred underlift charges and anticipates a similar situation in 1981.
In the event that the Company were unable to purchase enough low-sulphur fuel oil to meet its fuel oil requirements in the future, it might still be able to acquire higher-sulphur fuel oil. The Company's ability to burn such higher-sulphur fuel oil would be dependent upon obtaining variances from air pollution control regulations.
Nuclear fuel supply The Company has contractual arrangements covering 100% of the nuclear fuel cycle for San Onofre Nuclear Generating Station ("San Onofre") through the years indicated below:
Units Unit 1 2 & 3 Mining and milling to produce concentrates( )..................
1986 1985 C o nve rsio n 1990 1990 E n rich m e nt.............
20 14 2009 Fab ricatio n 1993 1985 Spent fuel storage(2)..................
1994 1994 (Footnotes on following page) 4
(1) The Company has contracted for approximately 68% of the uranium concentrates required for San Onofre Units 1, 2 and 3 from 1986 through 1990. Approximately 58% of the Com pany's uranium concentrate requirements for the period 1981 through 1990 are expected to be provided by a mine and mill in which Mono Power Company ("Mono"), a wholly-owned subsidiary of the Company, is a participant.
(2) The dates indicated assume full utilization of the capacities of on-site storage now existing and under construction and normal operations of these Units, including interpool transfers.
If additional storage or permanent disposal is unavailable when storage limits are reached, other arrangements will be required, the availability or cost of which the Company cannot predict at this time.
Participants in the Palo Verde Nuclear Generating Station Units 1, 2 and 3 ("Palo Verde")
have contractual commitments for the supply of uranium concentrates, conversion services and related fuel fabrication services required for approximately 17 years of operation for all three nuclear units. Contracts have also been.entered into with the Department of Energy for uranium enrichment services covering the estimated life of the three units.
Although the Palo Verde participants have no commitments for off-site storage of fuel discharged from reactors, on-site storage for spent fuel is being planned to accommodate normal operation through 1989 for Unit 1 and through later dates for Units 2 and 3. The timing and extent of off-site storage requirements cannot be accurately projected at this time.
Coal supply Coal supplies for the operation of the Mohave and Four Corners Projects are obtained pursuant to purchase contracts which extend over the expected useful lives of those projects and provide for the purchase of low-sulphur coal to support anticipated levels of operation during such periods.
Powerplant and Industrial Fuel Use Act of 1978 The Powerplant and Industrial Fuel Use Act of 1978 ("FUA") precludes the use of natural gas and petroleum fuels in new powerplants and limits the use of natural gas in existing power plants unless exemptions are obtained.
The Economic Regulatory Administration has issued a special rule for a temporary public interest exemption that encourages the near-term use of natural gas and permits existing powerplants to increase their natural gas consumption above that allowed by FUA. The Com pany has obtained such exemptions for all of its existing oil-and gas-fired powerplants.
Decontrol of crude oil and refined petroleum products In January 1981, President Reagan issued Executive Order No. 12287 and thereby exempted all crude oil and refined petroleum products from the price and allocation controls adopted pursuant to the Emergency Petroleum Allocation Act, as amended. The Order also terminated the entitlements program.
Decontrol and termination of entitlements will cause an increase in the price of domestic crude oil and'associated refined petroleum products. The extent of and impact on the Company of any price increases are expected to be minimal. Any such increases will be included in future ECAC filings. (See "Energy cost adjustment clause" under "Rate Matters".)
The effects on the Company of decontrol and termination of entitlements, other than the above mentioned price increases, are not presently known.
5
ENVIRONMENTAL MATTERS Legislation and regulation Legislative and regulatory activities in the areas of air pollution, water pollution, waste management, noise abatement, land use, aesthetics and nuclear control continue to result in the imposition of numerous restrictions on the operation by the Company of its existing facilities and on the timing, cost, location, design, construction and operation by the Company of new facilities required to meet its future load requirements. These activities substantially affect future planning and will continue to require modifications of the Company'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 two principal federal environmental statutes are the Clean Air Act, as amended, and the Clean Water Act. Both regulatory schemes are administered by the EPA in conjunction with state and local governments.
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. As a result, the Company may incur additional expenses in reducing or eliminating emissions at existing facilities and in constructing new facilities.
However, because major regulations relating to the 1977 amendments to the Act have not as yet been finalized, the Company is unable at this time to determine the extent to which such amendments will affect its operations and capital expenditures. In addition, the Act will be reopened for further amendments in 1981.
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 the 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, the Company is incurring additional expenses and capital expenditures. Additional regulations will be issued but the Company is unable to predict the extent to which such additional regula tions will affect its operations and capital expenditure requirements. The Company presently has discharge permits for all applicable facilities.
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 sub stantially increase the difficulty of siting new generating plants anywhere in California.
The Resource Conservation and Recovery Act provides the statutory authority for EPA to implement a regulatory program for the safe treatment, recycling, storage and disposal of solid and hazardous wastes.
EPA controls hazardous wastes with regulations on their generation, handling, storage and disposal. Thus far, these regulations have had only a minimal economic impact on expenditures.
Individual states may implement their own EPA approved hazardous waste programs in place of the federal scheme and may impose more stringent controls. The State of California is presently seeking EPA authorization to administer its own program. Furthermore, additional regulations are expected to be promulgated by EPA. As a consequence of the uncertainty in the future of the regulatory program, it is difficult to assess the extent to which operations and capital expenditures will be affected.
6
Currently pending environmental rulemaking and compliance proceedings and litigation involving the Company are discussed in "Environmental administrative proceedings and litigation" under Item 3. The effect of the Company's use of low-sulphur fuel oil required by air quality regulations is discussed in "Fuel Oil Supply" under "Fuel Supply."
Environmental expenditures The Company's estimated capitalized expenditures for environmental protection for the years 1969 through 1980 and its projected capital expenditures for such purposes for the years 1981 through 1985 are currently estimated as follows:
(Thousands of Dollars)
Air Water Solid Noise Additional pollution pollution waste abate-plant Miscel Years Total control control disposal ment Aesthetics capacity laneous 1969-1980
$890,679
$ 57,067
$ 24,074
$ 2,757
$ 4,365
$618,293
$ 3,746
$180,377 1981 246,056 101,831 9,609 37 3,441 104,067 27,071 1982 166,146 57,270 1,586 4
670 99,091 7,525 1983 253,536 133,036 268 189 894 97,366 21,783 1984 155,501 41,807 51 108,370 5,273 1985 133,320 43 122,660 10,617 These estimates include budgeted and forecast plant expenditures responsive to currently effective legislation and do not include potential costs associated with certain environmental proceedings.
(See "Environmental administrative proceedings and litigation" under Item 3.) 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 the Company's control. The Company believes that costs incurred for these environmental purposes will be recognized by the CPUC and the FERC as reasonable and necessary cqsts of service for rate purposes.
Item 2. Properties Existing generating facilities The Company owns and operates 13 oil-and gas-fueled electric generating plants, one diesel-fueled generating plant, 36 hydroelectric plants and Unit 1 (80% Company-owned) at the San Onofre Nuclear Generating Station located in central and southern California. In addition, the Company owns two small fossil-fueled electric generating units in Arizona and a 48% undivided interest (768 megawatts ("MW")) in Four Corners Units 4 and 5, a coal fueled steam electric generating plant in New Mexico ("Four Corners Project") all of which are operated by another utility. The Company also operates and owns a 56%
undivided interest (885 MW) in two coal-fueled steam electric generating units in Clark County, Nevada ("Mohave Project").
The Company also operates certain hydroelectric generating units owned by others in Arizona. Of the existing Company-owned generating capacity, approximately 78% is dependent on gas and oil fuel, 12% on coal, 3% on nuclear fuel and 7% is hydroelectric.
San Onofre, the Four Corners Project, certain of the Company's substations and certain 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 arrangements obligate the Company, under specified circumstances, at its expense to relocate transmission, 7
distribution and communication facilities located on lands owned or controlled by federal, state or local governments.
With certain exceptions, major and certain minor hydroelectric plants, with related reservoirs, having an effective operating capacity of 875 MW and located in whole or in part on lands of the United States, are owned and operated under government licenses which expire at various times between 1981 and 2009. Such licenses impose numerous restrictions and obligations on the Company, including the right of the United States to acquire the Company's hydroelectric plants upon payment of specified compensation. When original licenses expire, the FERC has authority to issue new licenses to third parties, but only upon payment of specified compensation to the Company. Any new licenses issued to the Company are expected to be issued upon terms and conditions less favorable than those of the expired licenses. Applica tions of the Company for the relicensing of certain of the hydroelectric plants referred to above with an aggregate effective operating capacity of 11.0 MW are pending, and until such proceedings are completed, the Company has been issued annual license renewals for such projects.
The record peak area demand experienced on the Company's system through December 31, 1980, was 12,841 MW on July 30, 1980. At the time of the peak, the total Company area system operating capacity available to the Company was approximately 15,504 MW.
Substantially all of the properties of the Company are subject to the lien of a trust indenture securing First and Refunding Mortgage Bonds, of which $3,027,530,000 principal amount was outstanding as of December 31, 1980. Such lien and the Company'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, the lien of another trust indenture to the extent referred to below, and liens of the trustees under such indentures. In addition such liens and the Company'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 the Company's right to use such properties in its business, unless the matters with respect to the Company's interest in the Four Corners Project. and the related easement and lease referred to below may be so considered.
The properties acquired by the Company pursuant to the merger in 1963 of California Electric Power Company, together with all substitutions, replacements, additions, alterations, improvements and enlargements to, of, or upon such properties are, with certain exceptions, also subject to the prior lien of another trust indenture securing $60,000,000 principal amount of First Mortgage Bonds originally issued by that company and outstanding as of December 31, 1980.
The Company'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, including possible conflicting grants or encumbrances not ascertainable because of the absence of or inadequacies in the applicable recording law and the record system of the Bureau of Indian Affairs and The Navajo Tribe, the possible inability of the Company to resort to legal process to enforce its rights against The Navajo Tribe without Con gressional consent and, in the case of the lease, possible impairment or termination under cer tain circumstances by Congress or the Secretary of the Interior. The Company cannot predict what effect, if any, such possible defects may have on its interest in the Four Corners Project.
Generating facilities under construction To serve loads in the service territory the Company currently has approximately 5,600 MW of new generating facilities and purchased power planned through 1990. Of the new generating facilities, 42%
will use nuclear fuel, 37%
will be from renewable/alternate 8
energy resources and 21%
will use other energy sources such as purchases, capacity exchanges and Edison's resale cities' own generation. The major generating facilities under construction are the following nuclear plants being built jointly with other utilities:
Company's share of Recorded Percent costs completed Estimated as of as of Net total December December Initial Full capacity cost(1) 31, 1980(1)
Facility Location 31, 1980 Power Facility (MW)
(000)
(000)
San-Onofre San Clemente, 86 1982-1983 76.55%
1,684
$2,625,000
$1,835,444 2,3 CA Palo Verde Wintersburg, 56 1983-1984 15.8 %
579 1,007,000 366,621 1, 2 & 3 AZ
& 1986 (1) Exclusive of fuel and related off-site transmission facilities. Estimates are subject to revision because of numerous factors, some of which are beyond the Company's control.
The application for an operating license for San Onofre Units 2 and 3 currently is under administrative review by an Atomic Safety Licensing Board, which has given persons opposed to operation of the units permission to intervene in the proceedings.
For further information, see "Construction program and capital expenditures."
Nuclear power developments As a result of evaluations of the accident at Three Mile Island Nuclear Power Plant ("TMI"),
the NRC required a review of the design and operating procedures of all operating or planned nuclear power plants.
San Onofre Unit 1 has been operating under a provisional operating license since 1968 and the Company's share is 349 MW. Although Unit 1 is different in design and manufacture from TMI, the Company has been ordered to implement certain design and operating procedure changes to allow continued operations. Pursuant to NRC order, the Company removed Unit 1 from service for approximately two weeks in the first quarter of 1980 to perform certain required design changes. Additional design changes have been and are being implemented during an outage which began on April 9, 1980 and has continued to date. The Company presently expects these design changes to be completed concurrently with the steam generator sleeving work described below. The Unit may be removed from service again in early 1982 for implementation of additional TMI-related modifications. The Company's share of the total cost of TMI-related modifications to Unit 1 is currently estimated at $30,000,000.
Inspection of the steam generators during the current shutdown revealed deterioration of a number of the steam generator tubes. A proposed remedy has been developed with the steam generator manufacturer which employs insertion and welding of sleeves into affected tubes. The remedy has received tentative approval by the NRC subject to final inspection and to NRC approval of significant changes in associated processes. Implementation of the sleeve insertion and welding process has encountered some technical problems which may limit its application.
Potential changes in the remedy have been developed such that the Company presently anticipates that the Unit will be returned to service in the second quarter of 1981. These potential changes include temporary removal of some steam generator tubes from service, pending resolution of the technical problems, with an associated temporary reduction in maximum electrical power generated. The Company's share of the total cost of the sleeving work is currently estimated at $40,000,000. If the current sleeving remedy is unsuccessful, the imple mentation of alternative remedies could involve significant additional expenditures. The Com 9
pany anticipates adequate generating capacity will be available from other generating resources during Unit 1 shutdowns.
The NRC has initiated a program, referred to as the Systematic Evaluation Program
("SEP"), for evaluating, against current criteria, eleven older operating nuclear units, including San Onofre Unit 1. The results of such evaluation may require significant analysis and modification during and beyond the evaluation period. A full-term operating license will not be issued until completion of the SEP.
In connection with the SEP, the Company has reinitiated a program to seismically reevaluate safety-related structures, systems and equip ment which have not previously been reevaluated. This reevaluation will require analysis which is now estimated to cost on the order of $14,000,000 for the Company's 80% share.
Plant modifications may be required as a result of the evaluation.
Also in connection with the SEP, the Company has been required by the NRC to dem onstrate compliance by June 30, 1982 with recently adopted requirements for assuring the ability of safety-related electrical equipment to remain operable during postulated accidents.
The Company has undertaken analyses of such equipment which may result in the need for plant modifications.
San Onofre Units 2 and 3, which are currently under construction, will also require certain design modifications as a result of the TMI accident. The Company's cost of such modifications is currently estimated at $24,000,000. The Company believes that currently required modifica tions could be accomplished without delaying the construction of such Units. However, because of slowed administrative processing of license applications by the NRC subsequent to TMI, the Company now projects a delay in the operation date of Unit 2 from the fourth quarter of 1981 to the second quarter of 1982, and of Unit 3 from the first quarter of 1983 to the third quarter of 1983. Because of these further delays, the Company's share of the total project cost has increased by approximately $140,000,000, primarily as a result of increased costs of carrying money invested in the project. An amount corresponding to any such increased carrying costs will be reflected in the Company's statements of income as a part of the AFUDC. The Company's projected operation date for Unit 2 assumes receipt of an operating license at a time six months prior to the date estimated by the NRC in the January 30, 1981 monthly status report to Congress. The Company believes, however, that its current schedule can be achieved, particularly in light of subsequent NRC proposals to streamline the licensing process.
Although higher energy costs will be incurred for alternative generating capacity during the periods that the San Onofre Units are not in operation, such costs will be included in future ECAC filings. The Company cannot predict what other effects, if any, including legislative or regulatory actions, the TMI accident may have upon it or upon the construction, licensing or future operation of its San Onofre Units or the Palo Verde Units or the extent of any additional costs it may incur as a result thereof.
Construction program and capital expenditures The Company presently anticipates that it will need approximately 5,600 MW of additional energy resources to serve its projected customer needs through 1990. Approximately 2,300 MW of new nuclear generating facilities are under construction (San Onofre Units 2 and 3 and Palo Verde Units 1, 2 and 3), and the Company plans to obtain approximately 1,200 MW from sources outside its service territory. The Company intends to pursue the accelerated develop ment of alternate and renewable energy resources (i.e., wind, geothermal, solar, fuel cells, hydroelectric and co-generation) to meet a portion of its future energy resource requirements.
The Company's present goal is to obtain substantially all of its remaining energy resource requirements from alternate and renewable energy resources. Because of lower forecasted demand, the Company cancelled the Harry Allen -
Warner Valley project, two coal-fired steam 10
electric generating plants, and has reclassified a second coal-fired project as a contingency resource.
The Company's construction program and related expenditures are continuously re viewed 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 the Company's control.
Funds used by the Company for construction expenditures totaled $567,831,000 in 1978,
$674,147,000 in 1979, and $781,510,000 in 1980. Construction expenditures for the 1981-1985 period are currently estimated as follows:
(Millions of dollars) 1981 1982 1983 1984 1985 Total Electric generating plants....................
$ 864
$ 699
$ 431
$ 307
$ 339
$2,640 Electric transmission lines and substations.....
110 63 139 150 118 580 Electric distribution lines and substations......
218 239 260 294 328 1,339 Other expenditures..........................
40 21 28 22 16 127 Total construction additions..................
1,232 1,022 858 773 801 4,686 Less allowance for funds used during construction 230 220 130 80 80 740 Funds required for construction expenditures...
$1,002
$ 802
$ 728
$ 693
$ 721
$3,946 Approximately 54% of the total electric generating plant expenditures for the years 1981 through 1985 are related to the construction of the new nuclear units at San Onofre and Palo Verde. The Company's share of the total cost of construction of these units is estimated to be
$2.6 billion and $1.0 billion, respectively, of which $1,835,000,000 and $367,000,000, respectively, had been expended through December 31, 1980. For further information, see "Generating facilities under construction."
Due to the high level of construction work in progress (primarily related to the con struction of San Onofre Units 2 and 3),
an increasing portion of the Company's net income in recent years has been attributable to AFUDC which does not contribute to the current cash flow of the Company. AFUDC constituted approximately 31%, 34% and 51%
of net income in 1978, 1979 and 1980, respectively. AFUDC is expected to decline significantly when San Onofre Units 2 and 3 are placed in commercial operation with a resulting reduction in this non-cash portion of net income. However, provided such Units receive appropriate and timely rate treatment, sufficient additional cash income is expected to be received to offset this decline in AFUDC.
To finance its construction program as shown in the above table for the five years through 1985, and to meet long-term debt maturities and preferred stock sinking fund requirements aggregating $529,536,000 during such years, the Company estimates that approximately $2.8 billion, or 60%, will be required from external sources. The balance of funds required for those purposes is expected to be obtained from internal sources, primarily during the latter part of such period with substantially all funds in 1981 and a substantial majority of funds in 1982 projected to be obtained from external sources.
The Company's estimates of funds available from internal sources assume the receipt of adequate and timely general rate relief, the timely inclusion of the new San Onofre Units and the Palo Verde Units in its rate base and the realization of its assumptions regarding cost increases, including the cost of capital. (See "Nuclear Power Developments".) The Company's estimates and underlying assumptions are subject to continuous review and periodic revision.
11
The timing, type and amount of all additional external financing are dependent upon market conditions, rate relief and other factors, including restrictions imposed by the Company's Articles of Incorporation and trust indenture.
Effect of governmental utilities and utility districts Under various acts of Congress, federal power projects have been constructed in California and neighboring states. Municipally-owned utilities, cooperative utilities and other public bodies have certain preference over investor-owned utilities in the purchase of electric power provided by federally funded power projects and, in addition, have certain preference over investor-owned utilities in connection with the acquisition of licenses to build hydroelectric power plants on federal lands. 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 the Company would result in a loss of sales by the Company.
Under the laws of California, utility districts may be formed and 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 the Company has previously served, the Company may experience a loss of customers.
The Company's construction permits for San Onofre Units 2 and 3 contain certain condi tions, the terms of which require the Company (i) to permit privately-or publicly-owned utilities, including the Company's resale customers, within or adjacent to the Company's service area, on timely notice, to participate on mutually agreeable terms in future nuclear units initiated by the Company, and (ii) to interconnect and coordinate reserves with, furnish emergency service to, sell to and purchase bulk power from, and provide certain transmission services for, such utilities.
The Company has also entered into agreements with certain of its resale customers which contemplate their possible participation in jointly-owned generating projects initiated by the Company, and the integration of power sources acquired by each such customer, including the dispatching, reserve sharing, partial power supply requirements and transmission services required in conjunction with such integrated operations. Pursuant to these agreements, two resale customers exercised an option to participate in the Company's ownership entitlement in San Onofre Units 2 and 3. The Company sold an undivided 3.45% interest in San Onofre Units 2 and 3 to these two resale customers for approximately $90,000,000. The foregoing conditions and agreements involve the potential additional loss of generation and transmission capacity and sales of power. The Company is unable to determine what effect these losses will have on its business and operations.
Item 3. Legal Proceedings Antitrust litigation In March 1978, five resale customers filed a suit against the Company in Federal Court alleging violation of certain antitrust laws. The complaint seeks damages in excess of
$23,000,000, consequential damages and a trebling of such damages and certain injunctive relief, and alleges that the Company (i) is engaging in anti-competitive behavior by charging more for wholesale electricity sold to the resale customers than the Company charges certain classes of its retail customers ("price squeeze"), and (ii) has taken actions 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' wholesale purchases from the Company. The foregoing proceedings involve complex issues of law and fact, and although 12
00 the Company is unable to predict their financial outcome or the possible effect of the FERC decision (discussed in "Rate Matters -
Resale rates" under Item 1) on the proceedings, it has categorically denied the allegations of these resale customers.
Fair employment practices matters In 1972, a charge was filed with the Federal Equal Employment Opportunity Commission
("EEOC") and a class action lawsuit was filed in Federal Court in 1974, both of which alleged that the Company had engaged in unlawful, discriminatory employment practices.
Although denying that it has engaged in any unlawful employment practices, the Company has entered into a Conditional Settlement with the EEOC and the representatives of most of the class action plaintiffs which, on November 7, 1977, was submitted to the Federal Court for approval as a consent decree. The estimated cost of this settlement is initially $700,000 with the possibility of an additional estimated $300,000 in payment on individual awards after hearings.
On September 23, 1980, the Court entered a consent decree which incorporated by reference the settlement agreement. Pursuant to the settlement agreement, the Company is implementing procedures designed to provide relief for class members. The Company believes, based on a current analysis of the applicable law and facts, that the cost of such relief and of any recovery for monetary damages, including back pay, should not have a material financial effect on the Company.
Department of Water and Power ("DWP") Service to California Department of Water Resources ("DWR")
In October 1979 DWP advised DWR that DWP would terminate service under a Suppliers Contract and would cease supplying energy under that contract. The Suppliers Contract provides that DWP and other suppliers, including the Company, will furnish energy.at the fixed rate of three mills per kilowatt-hour. The Company, on November 6, 1979, sought and received a preliminary injunction enjoining DWP from terminating service. The Company was required to post a $14,000,000 bond pending a trial on the merits. A stipulation is being negotiated which may reduce or eliminate the bond requirement.
If DWP were to prevail with its defense at the coming trial and be successful in uni laterally terminating its obligations to supply energy to DWR under the Suppliers Contract, and DWR were to prevail in its position that the Company must furnish 43% of DWP's obligation at the fixed three mills per kilowatt-hour price, the additional revenue deficiency from the Company's share of DWP's obligation up to the 1983 termination date of the Suppliers Contract is estimated to be approximately $57,000,000, based upon supply figures prepared by DWP.
Environmental litigation and administrative proceedings Four Corners Project The Four Corners Generating Station ("Four Corners") is a coal-fired, steam-electric power plant located in New Mexico, consisting of five generating units operated by Arizona Public Service Company ("APS"). Units 4 and 5, with 1,600 MW of capacity, are jointly owned.
The Company's share of these units is 48%, or 768 MW of capacity.
A prior New Mexico sulphur dioxide ("SO2") emission rule required that Units 4 and 5 achieve a 67.5% removal rate by December 1982. This rule has been approved by the EPA as part of the State Implementation Plan in accordance with the Clean Air Act.
A settlement agreement between APS and the New Mexico regulatory agencies, along with environmental groups, contemplates the adoption of a new SO2 rule which will require that Units 4 and 5 achieve a 72% removal rate by December 31, 1984. The settlement agreement is conditioned on approval of the new rule by the New Mexico Environmental Improvement 13
00 Board and the EPA prior to August 30, 1981.
The New Mexico Environmental Improvement Board on November 20, 1980 adopted a new rule (together with a new compliance schedule) consistent with the settlement agreement. This new rule and schedule of compliance were submitted by the Governor of New Mexico to the EPA for approval on November 24, 1980.
No action thereon has as yet been taken by the EPA. Because the December 31, 1982 com pliance date in the prior rule (which remains part of the EPA approved State Implementation Plan) and certain interim dates set out in the related compliance schedule do not allow for an orderly progression of design, procurement, and construction of the equipment needed for compliance, Four Corners may remain subject to the possibility of noncompliance penalties or unit shut down for S02 violations unless and until the new rule is approved by the EPA. The settlement agreement does not assure approval of the new rule and compliance schedule by the EPA.
Installation of the SO2 removal equipment which would be required to comply with the new rule will be in addition to the installation of the equipment now being constructed to meet the requirements of the New Mexico particulate emissions rule. APS has estimated that the cost for control of both pollutants will be $564,000,000. The Company's share of such estimated costs is approximately $270,000,000. The City of Farmington, New Mexico has recently issued
$92,500,000 of Pollution Control Bonds, which the Company is obligated to repay, to finance a portion of the Company's share of such costs.
Oxides of Nitrogen Rules All of the Company's conventional oil-and gas-fueled generating plants, which are located in the South Coast Air Basin, are subject to oxides of nitrogen rules ("NOx Rules") promulgated by the Air Resources Board ("ARB") for the South Coast Air Quality Management District
("SCAQMD") and the Ventura County Air Pollution Control District on December 18, 1980. The NOx Rules are designed to achieve an 80% reduction in oxides of nitrogen emissions from con ventional generating units by December 31, 1989.
The NOx Rules could require the Company to make substantial expenditures (up to
$500,000,000 in 1981 dollars) for pollution control equipment designed to effect an 80%
reduction in NOx emissions. The Company is continuing its challenges to the most recent version of the NOx Rules. A suit against the ARB regarding NOx Rules is scheduled to go to trial April 27, 1981. The NOx Rules would have required the submission of a final compliance plan before March 1, 1981. The Company, however, has acquired a stay of the application of the NOx Rules until the litigation is terminated.
Alamitos and Redondo Generating Stations In April 1979, the Company stipulated to an order with the SCAQMD to implement measures designed to prevent further emissions of particulates near the Company's Alamitos and Redondo Generating Stations. Compliance with the order will involve the expeditious refitting of certain of the power plants' machinery and equipment with more corrosion-resistant materials, and the early implementation of fuel additive injection and of specific stack washing and boiler cleaning techniques. The cost for implementation is currently estimated at $21,000,000. The Company will conduct a final test of the above particulate reduction measures by Fall 1981 for Alamitos and complete the testing for Redondo by Spring 1982. Data will be submitted to the SCAQMD for consideration. If the implemented measures are accepted by the SCAQMD, the order will be lifted in April 1982 for Alamitos and April 1983 for Redondo. The Company would then be required to maintain the effectiveness of such measures.
Management of polychlorinated biphenyls The Company has been meeting with the Los Angeles District Attorney to discuss the policies and practices directed to the cleanup, storage, and disposal of polychlorinated biphenyls 14
("PCBs"), a toxic substance utilized in certain electrical equipment. The District Attorney's office has indicated that it will file a lawsuit based on its assessment that certain state regulations governing the management of PCBs have been violated. The Company is aware of these regulations and has consistently striven to achieve compliance therewith. Based on the continued negotiations with the District Attorney's office and the Company's present PCB management practices, it is anticipated that any relief sought in the forthcoming lawsuit will not have a material financial effect on the Company.
Tax litigation The Navajo Tribal Council has adopted, but not yet implemented, a possessory interest tax, a business activity tax and a sulphur emissions tax which could apply to the Four Corners Project. The validity of these taxes is currently being litigated by participants in the Project.
The Company cannot predict the ultimate effect of these taxes, if implemented, upon future costs associated with the Four Corners Project or their effect upon costs of power or fuel derived from certain other Arizona and New Mexico operations.
Item 4. Security Ownership of Certain Beneficial Owners and Management (a) Security Ownership of Certain Beneficial Owners The following table presents certain information regarding shareholders(1) who are known to the Company to be beneficial owners of more than 5% of any class of the Company's voting securities as of December 31, 1980:
Amount and Name and Address Nature of Percent of Beneficial of Shareholder Class of Stock Ownership(2)
Class Searle & Co.
Preference 600,000 18.316%
General Post Office Box 3826 San Juan, Puerto Rico 00936
'Metropolitan Life Insurance
$100 Cumulative 750,000 14.634%
Company Preferred 1 Madison Avenue New York, New York 10010 Abbott Laboratories Preference 400,000 12.210%
Abbott Park North Chicago, Illinois 60064 Pfizer Pharmaceuticals Inc.
Preference 400,000 12.210%
235 East 42nd Street New York, New York 10017 Schering Pharmaceutical Preference 400,000 12.210%
Corporation (PR)
Post Office Box 486 Manati, Puerto Rico 00701 Garden St. Co.
Original Preferred 45,000 9.375%
140 Garden Street Hartford, Connecticut 06115 Abbott Chemicals Inc.
Preference 200,000 6.105%
Post Office Box 278 Barceloneta, Puerto Rico 00617 Upjohn Manufacturing Company Preference 200,000 6.105%
7000 Portage Road Kalamazoo, Michigan 49001 The Upjohn Manufacturing Preference 200,000 6.105%
Company M 7000 Portage Road Kalamazoo, Michigan 49001 (Footnotes on following page) 15
(1) In addition, 4,933,570 shares of Common Stock (6.504% of the class) are held in trust by certain of Western Bancorporation's (707 Wilshire Boulevard, Los Angeles, California 90017) subsidiary banks in their fiduciary capacities. One of these subsidiaries, United California Bank, acts as trustee for Company employees participating in the Employee Stock Purchase Plan and held of record, as of December 31, 1980, 4,890,997 shares in its nominee name for this purpose. This nominee furnishes voting instruction materials to the beneficial owners of the plan shares held by it. These shares are voted in accordance with instructions given by employees. Shares for which instructions are not received may be voted by the trustee in its discretion.
(2) In all cases, shares are held in the name of the shareholder shown.
(b) Security Ownership of Management The following table presents certain information regarding the equity securities of the Company beneficially owned by the Directors and Executive Officers(1) as of December 31, 1980:
Amount and Nature of Percent Beneficial of Name Class of Stock Ownership(2)
Class Howard P. Allen Common 6,948 shares 0.009%
Original Preferred 30 shares(3) 0.006%
Roy A. Anderson Common 200 shares(3)
(4)
Norman Barker, Jr.
Common 100 shares (4)
Edward W. Carter Common 500 shares 0.001%
William B. Coberly, Jr.(5)
Common 348 shares (4)
Terrell C. Drinkwater(5)
Common 100 shares (4)
Walter B. Gerken Common 100 shares (4)
William R. Gould Common 9,153 shares(6) 0.012%
Joan C. Hanley Common 1,000 shares 0.001%
Jack K. Horton Common 11,262 shares(7) 0.015%
$100 Cumulative Preferred 5 shares (3)
(4)
Frederick G. Larkin, Jr.
Common 100 shares (4)
T. M. McDaniel, Jr.
Common 6,170 shares 0.008%
Original Preferred 140 shares 0.029%
John V. Newman Common 2,600 shares(8) 0.003%
Cumulative Preferred 100 shares (9) 0.001%
Gerald H. Phipps Common 18,435 shares(10) 0.024%
Original Preferred 450 shares (11) 0.094%
Cumulative Preferred 8,940 shares(12) 0.079%
Henry T. Segerstrom Common 1,000 shares 0.001%
E. L. Shannon, Jr.
Common 100 shares (4)
H. Russell Smith Common 1,000 shares 0.001%
Richard R. Von Hagen Common 500 shares 0.001%
All Directors and Common 107,692 shares(13) 0.142%
Executive Officers Original Preferred 660 shares(14) 0.138%
as a Group Cumulative Preferred 9,249 shares(15) 0.081%
(34 individuals)
$100 Cumulative Preferred 30 shares(3) 0.001%
(Footnotes on following page) 16
(1) The Executive Officers are the Chairman of the Board and Chief Executive Officer, the President, the elected Vice Presidents, the General Counsel and the Secretary of the Company.
(2) Unless otherwise indicated, shares are held with sole voting and investment power.
(3) Shares are held with another person.
(4) Less than 0.001%.
(5) Messrs. Coberly and Drinkwater, having reached retirement age, are not Nominees for reelection to the Board of Directors in 1981.
(6) Includes 30 shares held with another person.
(7) Includes 140 shares held with another person.
(8) Includes 900 shares held by spouse as trustee.
(9) Shares are held by spouse as trustee.
(10) Includes 510 shares held by spouse and 735 shares for which the Director has shared voting and investment power, but disclaims any beneficial interest.
(11)
The Director has shared voting and investment power, but disclaims any beneficial interest.
(12) Includes 6,540 shares for which the Director has shared voting and investment power but disclaims any beneficial interest.
(13) Includes 1,654 shares held with other persons, 2,900 shares held in trustee accounts, 2,970 shares held by spouses, 2,192 shares held in a broker's name, and the 735 shares described in Note 10 above.
(14)
Includes 30 shares held with other persons, 10 shares held in custodian accounts and the shares described in Note 11 above.
(15) Includes 109 shares held with other persons, 100 shares held in custodian accounts, 100 shares held by spouses, and the 6,540 shares described in Note 12 above.
17
Executive Officers of the Registrant Age at December 31, Effective Executive Officer 1980 Company Position Date William R. Gould 61 Chairman of the Board, Chief Executive Officer July 1,1980 and Director Howard P. Allen 55 President and Director July 1, 1980 H. Fred Christie 47 Executive Vice President and Chief Financial Officer July 1, 1980 David J. Fogarty 53 Senior Vice President September 1, 1977 A. Arenal 55 Vice President (Engineering and Construction)
January 1,1980 Glenn J. Bjorklund 48 Vice President (System Development)
August 1,1979 Robert Dietch 42 Vice President (Nuclear Engineering and Operations)
January 1, 1980 C. E. Hathaway 46 Vice President (Human Resources)
January 1, 1980 Joe T. Head, Jr.
59 Vice President (Power Supply)
November 21, 1974 P. L. Martin 51 Vice President (Customer Service)
September 1,1978 A. L. Maxwell 59 Vice President and Comptroller July 17, 1975 Edward A. Myers, Jr.
57 Vice President (Conservation, Communications August 19, 1971 and Revenue Services)
Michael L. Noel 39 Vice President and Treasurer July 1,1980 Lawrence T. Papay 44 Vice President (Advanced Engineering)
January 1,1980 William H. Seaman 63 Vice President (Fuel Supply)
July 17, 1969 Robert E. Umbaugh 43 Vice President (Administration)
September 1,1976 John R. Bury 53 General Counsel September 1,1978 Honor Muller 52 Secretary November 1, 1979 None of the Company's executive officers are related to each other by blood or marriage.
All of the executive officers have been actively engaged in the business of the Company for more than five years.
All officers have been employees of the Company for the past five years. Those officers who have not held their present position for the past five years had the following business experience during that period:
William R. Gould President and Director February 1978 to June 1980 Executive Vice President December 1973 to January 1978 Howard P. Allen Executive Vice President December 1973 to June 1980 H. Fred Christie Senior Vice President and Chief Financial Officer January 1977 to June 1980 Senior Vice President September 1976 to December 1976 Vice President and Treasurer July 1975 to August 1976 David J. Fogarty Vice President - Customer Service September 1976 to August 1977 Vice President -
Power Supply December 1974 to August 1976 A. Arenal Vice President-Advanced August 1979 to Engineering December 1979 Vice PresidentJ-System September 1976 to Development July 1979 Manager of Engineering and November 1971 to Construction August 1976 18
0 0
Glenn J. Bjorklund Division Vice President -
Eastern Division May 1978 to August 1979 Administrator ofDepartment Operations-May 1975 to Customer Service Staff May 1978 Robert Dietch Division Manager -
Southeastern Division August 1979 to December 1979 Assistant Division Manager October 1978 to Southeastern Division July 1979 Manager of Projects -
January 1978 to Project Management Organization September 1978 Manager of Engineering Design Organization January 1976 to December 1977 Manager of Construction and Transmission/
February 1975 to Substation Engineering December 1975 C. E. Hathaway Division Vice President -
Eastern Division August 1979 to December 1979 Division Vice President -
Southeastern Division September 1978 to July 1979 Division Vice President -
Central Division January 1978 to August 1978 Assistant Division Manager -
Central Division May 1975 to December 1977 Joe T. Head, Jr.
Vice President -
System Development December 1974 to August 1976 P. L. Martin Division Vice President -
Southeastern September 1977 to Division August 1978 Division Manager -
Southeastern Division December 1973 to August 1977 Michael L. Noel Treasurer August 1976 to June 1980 Assistant Treasurer December 197510 August 1976 Lawrence T. Papay General Superintendent -
Power Supply October 1978 to December 1979 Director of Research and Development August 1970 to September 1978 Robert E. Umbaugh Manager of Data Processing January 1974 to August 1976 John R. Bury Assistant General Counsel December 1973 to August 1978 Honor Muller Assistant Secretary December 1978 to October 1979 Executive Secretary February 1959 to December 1978 19
0 0
PART II Item 5. Market for the Registrant's Common Stock and Related Security Holder Matters Information responding to Item 5 was included in the Company's Annual Report to Share holders for the year ended December 31, 1980 ("Annual Report") under "Capital Stock Dividend Price Information" and is incorporated by reference pursuant to General Instruction G.
Additional information concerning the market for the Company's Common Stock is set forth on the cover page.
Item 6. Selected Financial Data Information responding to Item 6 was included in the Annual Report under "Selected Financial Data 1970-1980" and is incorporated herein by reference pursuant to General Instruc tion G.
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations Information responding to Item 7 was included in the Annual Report under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and is incorporated herein by reference pursuant to General Instruction G.
Item 8. Financial Statements and Supplementary Data Certain information responding to Item 8 is set forth after Item 11 in Part IV. Other informa tion responding to Item 8 was included in the Annual Report on pages 18-33 and is incorporated herein by reference pursuant to General Instruction G.
PART III Item 9. Directors and Officers of the Registrant Information concerning directors and officers of the Company is set forth after Item 4 in Part I, pursuant to Instruction 4 to Item 3(b) of Regulation S-K. Other information responding to Item 14 was included in a proxy statement filed by the Company on or about March 4, 1981 with the Commission pursuant to Regulation 14A ("Proxy Statement") on pages 2-5 and is incorporated herein by reference pursuant to General Instruction G.
Item 10. Management Remuneration and Transactions Information responding to Item 10 was included in the Proxy Statement on pages 6-10 and is incorporated herein by reference pursuant to General Instruction G.
PART IV Item 11.
Exhibits, Financial Statement Schedules and Reports on Form 8-K 11(a)
Documents Filed 11(a)(1)
Financial Statements Incorporated by reference to the Annual Report:
Management's Discussion and Analysis of Financial Condition and Results of Operations Report of Independent Public Accountants 20
Statements of Income -Years Ended December 31, 1980, 1979 and 1978 Balance Sheets -
December 31, 1980 and 1979 Statement of Changes in Financial Position -Years Ended December 31, 1980, 1979 and 1978 Statements of Earnings Reinvested in the Business and Statements of Additional Paid-In Capital -Years Ended December 31, 1980, 1979 and 1978 Statements of Capital Stock -
December 31, 1980 and 1979 Statements of Long-term Debt -December 31, 1980 and 1979 Notes to Financial Statements Supplementary Information to Disclose the Effects of Changing Prices (Unaudited) 11(a) (2)
Report of Independent Public Accountants and Schedules Supporting Financial Statements Included after Item 11 in Part IV.
Page Schedule V -
Property, Plant and Equipment for the Years Ended December 31, 1980, 1979 and 1978..
23 Schedule VI -Accumulated Depreciation and Amortization of Prop erty, Plant and Equipment for the Years Ended December 31, 1980, 1979 and 1978 26 Schedule VIII -Valuation and Qualifying Accounts for the Years Ended December 31, 1980,1979 and 1978 29 Schedule IX -
Short-Term Borrowings 32 Information Required by Schedule X was included in the Annual Report on page 28.
Schedules I to XIII, inclusive, except those referred to above, are omitted as not required or not applicable.
11(a)(3) Exhibits See Exhibit Index on page 35.
11(b)
Reports on Form 8-K None 21
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON SUPPORTING SCHEDULES To Southern California Edison Company:
In connection with our examination of the financial statements included in the 1980 Annual Report to Shareholders of Southern California Edison Company and incorporated by reference in this Form 10-K, we have also examined the supporting schedules listed in the index herein.
In our opinion, these schedules present fairly, when read in conjunction with the related financial statements, the financial data required to be set forth therein, in conformity with generally accepted accounting principles applied on a consistent basis.
ARTHUR ANDERSEN & CO.
Los Angeles, California, February 6, 1981.
22
SOUTHERN CALIFORNIA EDISON COMPANY SCHEDULE V -
PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1980 (Thousands of Dollars)
Add (Deduct)Banc Balance at Beginning Additions Other at End Classification of Period at Cost Retirements Changes of Period Steam Production
$1,340,840 18,427 (1,966)
$1,357,301 Nuclear Production 156,027 13,903 (151) 169,779 Hydro Production 216,809 18,130 (223) 7 234,723 Other Production 354,680 230 (2)
(271) 354,637 Transmission.....
1,186,035 49,977 (2,759) 3,509 1,236,762 Distribution......
2,069,431 168,898 (22,148)
(290) 2,215,891 General..........
146,821 27,829 (1,892)
(2,955) 169,803 Plant Held for Future Use.....
26,069 (286)
(2) 25,781 Experimental Electric Plant Unclassified....
107 14,176 14,283 Other Utility Plant 6,165 78 (3) 6,240 Subtotal Utility Plant 5,502,984 311,362 (29,146) 5,785,200 Construction Work in Progress....
2,058,958 622,206 (1,441)
(79,263)(a) 2,600,460 Nuclear Fuel......
40,616 12,050 (6,728) (a) 45,938 Gross Utility Plant......
$7,602,558
$ 945,618
$ (30,587)
$ (85,991)
$8,431,598 Nonutility Property 9,209 737 (763) 9,183 (a) Represents the cost of the interest in San Onofre Nuclear Generating Station Units 2 and 3 which was sold to the cities of Anaheim and Riverside.
23
0 SOUTHERN CALIFORNIA EDISON COMPANY SCHEDULE V -
PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1979 (Thousands of Dollars)
Balance at Add (Deduct)
Balance Beginning of Additions Other at End Classification Period at Cost Retirements Changes of Period Steam Production
$1,323,603 18,515 (1,278)
$1,340,840 Nuclear Production 145,565 10,493 (31) 156,027 Hydro Production 215,647 1,333 (161)
(10) 216,809 Other Production 350,002 4,678 354,680 Transmission.....
1,164,523 30,276 (6,628)
(2,136) 1,186,035 Distribution......
1,930,266 158,939 (19,576)
(198) 2,069,431 General..........
139,374 7,496 (2,999) 2,950 146,821 Plant Held for Future Use.....
28,373 1,615 (1,636)
(2,283) 26,069 Experimental Electric Plant Unclassified....
217 107 (217) 107 Other Utility Plant 6,176 1,019 (10)
(1,020) 6,165 Subtotal Utility Plant 5,303,746 234,471 (32,319)
(2,914) 5,502,984 Construction Work in Progress....
1,493,573 564,504 881 2,058,958 Nuclear Fuel.....
36,353 4,263 40,616 Gross Utility Plant......
$6,833,672
$ 803,238
$ (31,438)
(2,914)
$7,602,558 Nonutility Property 7,182 4,438 (2,411) 9,209 24
SOUTHERN CALIFORNIA EDISON COMPANY SCHEDULE V -
PROPERTY, PLANT AND EQUIPMENT FOR THE YEAR ENDED DECEMBER 31, 1978 (Thousands of Dollars)
Balance at Add (Deduct)
Balance at Beginning Additions Other End Classification of Period at Cost Retirements Changes of Period Steam Production..........
$1,302,084 $
23,829 $
(2,310) $
$1,323,603 Nuclear Production...........
133,516 12,051 (2) 145,565 Hydro Production..........
215,523 391 (267) 215,647 Other Production..........
201,088 148,914 350,002 Transmission..............
1,127,702 39,693 (3,058) 186 1,164,523 Distribution................
1,820,103 128,404 (18,052)
(189) 1,930,266 General....................
130,978 12,370 (3,968)
(6) 139,374 Plant Held for Future Use..
29,226 (851)
(2) 28,373 Experimental Electric Plant Unclassified........
699 (482) 217 Other Utility Plant..........
3,969 2,245 (38) 6,176 Subtotal -
Utility Plant..
4,964,888 366,564 (27,697)
(9) 5,303,746 Construction Work in Progress 1,209,502 285,122 (1,051) 1,493,573 Nuclear Fuel..............
37,213 608 (1,468) (a) 36,353 Gross Utility Plant......
$6,211,603 $ 652,294 $ (28,748) $
(1,477) $6,833,672 Nonutility Property.........
5,725 $
1,123 (2,783) $
3,117 $
7,182 (a) Represents nuclear fuel sold and leased back.
25
SOUTHERN CALIFORNIA EDISON COMPANY SCHEDULE VI-ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT(a)
FOR THE YEAR ENDED DECEMBER 31, 1980 (Thousands of Dollars)
Additions Add (Deduct)
Balance at Charged to Balance at Beginning Costs and Other End Description of Period Expenses Retirements Changes(b)
Salvage of Period Steam Production
$ 578,032
$ 38,947 $ (1,949) $
(186) $
16
$ 614,860 Nuclear Production 39,169 9,455 (9)
(27) 7 48,595 Hydro Production 88,109 3,570 (225)
(7) 34 91,481 Other Production 57,647 15,229 (2) 1 72,875 Transmission 240,888 33,010 (2,007)
(501) 1,146 272,536 Distribution 639,263 81,730 (21,420)
(7,698) 8,094 699,969 General 35,792 7,412 (1,959) 225 120 41,590 Experimental Electric Plant Unclassified 6
1,013 1,019 Retirement Work in Progress (3,766)
(2,279)
(449) 2,634 (3,860)
Other Utility Plant Reserves 1,008 164 (3)
(1) 1,168 Subtotal 1,676,148 190,530 (29,853)
(8,643) 12,051 1,840,233 Nuclear Fuel Amortization 24,888 401 25,289 Total Utility Plant Reserves......
$1,701,036
$190,931
$(29,853) $ (8,643) $ 12,051
$1,865,522 Nonutility Property Reserves...........
951 105 (798) $
714 972 (a) Depletion is not applicable.
(b) Includes removal costs related to facilities retired, damage claims and relocation costs collected from others, and various other adjustments of depreciation and amortization.
26
SOUTHERN CALIFORNIA EDISON COMPANY SCHEDULE VI-ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT(a)
FOR THE YEAR ENDED DECEMBER 31, 1979 (Thousands of Dollars)
Additions Add (Deduct)
Balance at Charged to Balance at Beginning Costs and Other End Description of Period Expenses Retirements Changes(b)
Salvage of Period Steam Production........
$ 540,254 38;876 $
(1,140) $
11 31
$ 578,032 Nuclear Production 30,205 9,009 (30)
(15) 39,169 Hydro Production 84,979 3,322 (172)
(40) 20 88,109 Other Production 42,409 15,250 (12) 57,647 Transmission 212,944 32,026 (6,265)
(760) 2,943 240,888 Distribution 579,316 76,292 (19,453)
(4,120) 7,228 639,263 General 31,399 6,719 (2,877)
(240) 791 35,792 Experimental Electric Plant Unclassified 1
5 6
Retirement Work in Progress...............
(3,207) 774 (1,560) 227 (3,766)
Other Utility Plant Reserves 874 143 (9)
(1) 1 1,008 Subtotal............
1,519,174 181,642 (29,172)
(6,737) 11,241 1,676,148 Nuclear Fuel Amortization.
22,781 2,107 24,888 Total Utility Plant Reserves.........
$1,541,955 $ 183,749 $ (29,172) $
(6,737) $
11,241
$1,701,036 Nonutility Property Reserves..............$
1,267 $
78 $
(872) $
478 $
951 (a) Depletion is not applicable.
(b) Includes removal costs related to facilities retired, damage claims and relocation costs collected from others, and various other adjustments of depreciation and amortization.
27
0 SOUTHERN CALIFORNIA EDISON COMPANY SCHEDULE VI-ACCUMULATED DEPRECIATION AND AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT(a)
FOR THE YEAR ENDED DECEMBER 31, 1978 (Thousands of Dollars)
Additions Add (Deduct)
Balance at Charged to Balance at Beginning Costs and Other End Description of Period Expenses Retirements Changes(b)
Salvage of Period Steam Production........$
500,979 39,503 $
(472) $
242 $
2 $ 540,254 Nuclear Production......
24,405 5,800 30,205 Hydro Production........
82,163 3,119 (265)
(40) 2 84,979 Other Production........
32,258 11,469 (1,318) 42,409 Transmission............
189,057 25,026 (2,926) 599 1,188 212,944 Distribution.............
526,102 69,197 (17,541)
(4,221) 5,779 579,316 General................
29,205 5,791 (3,989)
(71) 463 31,399 Experimental Electric Plant Unclassified..
208 95 (302) 1 Retirement Work in Progress.............
(2,172)
(925) 426 (536)
(3,207)
Other Utility Plant Reserves 804 103 (34) 1 874 Subtotal............
1,383,009 160,103 (26,152)
(4,685) 6,899 1,519,174 Nuclear Fuel Amortization 19,870 2,911 22,781 Total Utility Plant Reserves.........
$1,402,879 $ 163,014 $ (26,152) $
(4,685) $
6,899 $1,541,955 Nonutility Property Reserves............
1,133 134 1,267 (a) Depletion is not applicable.
(b) Includes removal costs related to facilities retired, damage claims and relocation costs collected from others, and various other adjustments of depreciation and amortization.
28
SOUTHERN CALIFORNIA EDISON COMPANY SCHEDULE VIII-VALUATION AND QUALIFYING ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 1980 (Thousands of Dollars)
Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End Description of Period Expenses Accounts Deductions of Period Group A:
Uncollectible Accounts Customers................
$ 2,263
$ 7,806
$ 6,403
$ 3,666 All Other..................
6,233 (37) 1,857 4,339 Total.........
$ 8,496
$ 7,769
$ 8,260 (a) $ 8,005 Group B:
Pensions and Benefits........
$17,739
$ 9,348
$ 9,756(b) $15,257(c) $21,586 Insurance, Casualty and Other 14,809 30,151 26,609(d) 18,351 Total.............
$32,548
$39,499
$ 9,756
$41,866
$39,937 (a) Accounts written off, net.
(b) Principally, charges are to various plant and expense accounts as a payroll additive for employees' paid absences.
(c) Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.
(d) Principally charges from work orders closed and amounts charged to operations that were not covered by insurance.
29
0 0
SOUTHERN CALIFORNIA EDISON COMPANY SCHEDULE VIII-VALUATION AND QUALIFYING ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 1979 (Thousands of Dollars)
Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End Description of Period Expenses Accounts Deductions of Period Group A:
Uncollectible Accounts Customers
$ 2,059
$ 4,770
$ 4,566
$ 2,263 All Other,.................
3,549 3,565 881 6,233 Total.............
$ 5,608
$ 8,335
$ 5,447(a) $ 8,496 Group B:
Pensions and Benefits.........
$15,536
$ 5,728
$ 8,705(b) $12,230(c) $17,739 Insurance, Casualty and Other..
11,089
.23,282 19,562(d) 14,809 Total.............
$26,625
$29,010
$ 8,705
$31,792
$32,548 (a) Accounts written off, net.
(b) Principally, charges are to various plant and expense accounts as a payroll additive for employees' paid absences.
(c) Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.
(d) Principally charges from work orders closed and amounts charged to operations that were not covered by insurance.
30
SOUTHERN CALIFORNIA EDISON COMPANY SCHEDULE VIII-VALUATION AND QUALIFYING ACCOUNTS FOR THE YEAR ENDED DECEMBER 31, 1978 (Thousands of Dollars)
Additions Balance at Charged to Charged to Balance at Beginning Costs and Other End Description of Period Expenses Accounts Deductions of Period Group A:
Uncollectible Accounts Customers...............
$ 2,050
$ 4,110 15
$ 4,116
$ 2,059 All Other.
3,664 1,097 1,212 3,549 Total............
$ 5,714
$ 5,207 15
$ 5,328(a) $ 5,608 Group B:
Pensions and Benefits........
$17,497 869
$ 8,335(b) $11,165(c) $15,536 Insurance, Casualty and Other 11,956 28,757 29,624(d) 11,089 Total.............
$29,453
$29,626
$ 8,335
$40,789
$26,625 (a) Accounts written off, net.
(b) Principally, charges are to various plant and expense accounts as a payroll additive for employees' paid absences.
(c) Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.
(d) Pursuant to a FERC order, operating reserves relating to certain federally-licensed hydro electric projects in the amount of $3,801,000 were transferred to Earnings Reinvested in the Business and became an appropriation thereof. Other deductions were principally charges from work orders closed and amounts charged to operations that were not covered by insurance.
31
SOUTHERN CALIFORNIA EDISON COMPANY SCHEDULE IX -
SHORT-TERM BORROWINGS Weighted Maximum Average Average Weighted Amount Amount Interest Balance at Average Outstanding Outstanding Rate End of Interest During During During Period Rate the year the year the year (000)
(000)
(000)(A)
(B)
December 31, 1980 Notes Payable to banks.....
$ 19,998 16.875%
$ 45,996
$ 20,296 12.79%
Payable to holders of Commercial Paper.......
164,975 15.29 %
489,395 299,873 11.85%
Bankers Acceptances......
30,860 7,723 17.35%
December 31, 1979 Notes Payable to banks.....
19,840 13.75 %
20,078 20,052 11.01%
Payable to holders of Commercial Paper.......
134,340 13.73 %
184,340 65,057 11.08%
December 31, 1978 Notes Payable to banks.....
19,986 10.50 %
87,970 41,402 8.23%
Payable to holders of Commercial Paper.......
165,273 113,414 7.23%
Bankers Acceptances......
68,545 24,259 7.87%
(A)
Average amount outstanding during the year is computed by dividing the total of daily outstanding principal balances by 366 for 1980 and 360 for 1979 and 1978.
(B) Weighted average interest rate during the year is computed by dividing the total interest expense by the average amount outstanding.
32
SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Annual Report on Form 10-K to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Rosemead, and State of California.
SOUTHERN CALIFORNIA EDISON COMPANY By MICHAEL L. NOEL (Michael L. Noel, Vice President and Treasurer)
Date: March 19, 1981 Pursuant to the requirements of the Securities Exchange Act of 1934, this Annual Report on Form 10-K has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature Title Date Principal Executive Officer:
William R. Gould*
Chairman of the Board, March 19, 1981 Chief Executive Officer and Director Principal Financial Officer:
H. Fred Christie*
Executive Vice President March 19, 1981 and Chief Financial Officer Controller or Principal Accounting Officer:
A. L. Maxwell*
Vice President and March 19, 1981 Comptroller Directors:
Howard P. Allen*
President and Director March 19, 1981 Roy A. Anderson*
Director March 19, 1981 N. Barker, Jr.*
Director March 19, 1981 Edward W. Carter*
Director March 19, 1981 William B. Coberly, Jr.*
Director March 19, 1981 Terrell C. Drinkwater*
Director March 19, 1981 Walter B. Gerken*
Director March 19, 1981 Joan C. Hanley*
Director March 19, 1981 J. K. Horton*
Director March 19, 1981 F. G. Larkin, Jr.*
Director March 19, 1981 T. M. McDaniel, Jr.*
Director March 19, 1981 John V. Newman*
Director March 19, 1981 Gerald H. Phipps Director March 19, 1981 Henry T. Segerstrom*
Director March 19, 1981 E. L. Shannon, Jr.*
Director March 19, 1981 H. Russell Smith*
Director March 19, 1981 Richard R. Von Hagen*
Director March 19, 1981
- By MICHAEL L. NOEL (Michael L. Noel, Attorney-in-Fact) 33
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS As independent public accountants, we hereby consent to the incorporation by reference of our report (the Report of Independent Public Accountants) appearing on Page 18 of the 1980 Annual Report to Shareholders of Southern California Edison Company (Exhibit 13 included herein) in the annual report on Form 10-K for the year ended December 31, 1980 of Southern California Edison Company.
We further consent to the incorporation by reference of the above-mentioned Report of Independent Accountants, incorporated by reference in the annual report on Form 10-K, and to the incorporation by reference of our report (the Report of Independent Public Accountants on Supporting Schedules), appearing on Page 22 in the annual report on Form 10-K, in the Registration Statement on Form S-16 which became effective on April 7, 1980 (File No. 2-66939).
ARTHUR ANDERSEN & CO.
Los Angeles, California March 19, 1981 34
EXHIBIT INDEX A.
Form 11-K for the Company's Employee Stock Purchase Plan B.
Form 11-K for the Company's Employee Stock Ownership Plan C.
Proxy Statement filed by the Company on or about March 4, 1981 with the Securities and Exchange Commission pursuant to Regulation 14A*
3 (a)'
Restated Articles of Incorporation as amended through April 24, 1980 (File No. 1-2313)*
3 (b)
Bylaws as revised effective July 1, 1980 (File No. 1-2313)
- 4.
The following exhibits have heretofore been physically filed with the Securi ties and Exchange Commission (specified document and file number noted) and are incorporated herein by reference pursuant to Rule 12b-23:
(a) Forty-Sixth Supplemental Indenture, dated as of November 15, 1980 (Form S-16, File No. 2-69609, effective November 19, 1980)
(b) Resolution Creating First and Refunding Mortgage Bonds, Series 00, Due 2010, dated November 19, 1980 (Form S-16, File No. 2-69609, effective November 13, 1980)
- 10.
Material Contracts (a) Executive Supplemental Benefit Program (b) Consulting Agreement between the Company and Jack K. Horton, Director, dated July 1, 1980
- 11.
Computation of Fully Diluted Earnings Per Share
- 13.
Annual Report to Shareholders for year ended December 31, 1980 (only portions of which are incorporated herein by reference)
- Incorporated by reference to Rule 12b-32.
35
9 Exhibit 11 SOUTHERN CALIFORNIA EDISON COMPANY COMPUTATION OF FULLY DILUTED EARNINGS PER SHARE (Thousands of Dollars)
Year Ended December 31, 1980 1979 1978 Net Income
$317,536
$346,219
$251,683 Less: Preferred and Preference dividend require ments.................
62,284 54,967 50,532 Add: Original Preferred dividends 1,334 1,229 1,075 Add:
Convertible Preference dividend require ments 1,149 1,592 2,354 Add: Interest on 3/8% Convertible Debentures.2,341 2,341 Less: Tax effect of interest on 3Ve8%
Convertible Debentures(A) 1,190 1,233 Adjusted amount available
$257,735
$295,224
$205,688 Weighted average shares Original Preferred 480,000 480,000 480,000 Common(B) 72,864,813 63,887,178 57,199,490 Common shares reserved for conversion of:
3V % Convertible Debentures 2,024,380 1,997,388 Preference Stock, 5.20% Convertible Series 612,230 796,088 1,202,809 Total weighted average shares 73,957,043 67,187,646 60,879,687 Fully diluted earnings per share(C)
$3.48
$4.39
$3.38 Notes:
(A) Composite tax rate............
50.86%
52.68%
(B)
Includes Common Stock equivalents and Common Stock issued due to conversions during 1980, 1979, and 1978 adjusted as if they were outstanding at the beginning of the year.
(C)
Adjusted amount available divided by total weighted average shares.
36