ML13326A957
| ML13326A957 | |
| Person / Time | |
|---|---|
| Site: | San Onofre, Palo Verde  |
| Issue date: | 05/17/1995 |
| From: | Marsh W SOUTHERN CALIFORNIA EDISON CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| NUDOCS 9505240366 | |
| Download: ML13326A957 (44) | |
Text
/7=
Southern California Edison Company 23 PARKER STREET IRVINE, CALIFORNIA 92718 WALTER C. MARSH May 17, 1995 TELEPHONE MANAGER OF NUCLEAR REGULATORY AFFAIRS (714) 454-4403 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555 Gentlemen:
Subject:
Docket Nos. 50-206, 50-361, 50-362, 50-528, 50-529, and 50-530 Internal Cash Flow for San Onofre Nuclear Generating Station Units 1,2,&3 and Palo Verde Nuclear Generating Station Units 1,2,&3 The enclosed Cash Flow Statement for the year ending December 31, 1994 is submitted in accordance with 10 CFR Part 140.21(e) for Southern California Edison Company, as agent for the owners of San Onofre Nuclear Generating Station Units 1,2 and 3 and for Southern California Edison Company's 15.8%
share of Palo Verde Nuclear Generating Station Units 1,2 and 3.
The SCEcorp Annual Report to the Securities and Exchange Commission (Form 10-K) for the year ending December 31, 1994 is also enclosed for your information.
If you have any questions or require further information, please contact me.
Sincerely, cc:
L. J. Callan, Regional Administrator, NRC Region IV A. B. Beach, Director, Division of Reactor Projects, Region IV K. E. Perkins, Jr., Director, Walnut Creek Field Office, NRC Region IV J. A. Sloan, NRC Senior Resident Inspector, San Onofre Units 2 & 3 M. B. Fields, NRC Project Manager, San Onofre Units 2 and 3 950524036 6 950517 PDR ADOCK 05000206 PDR 9
SOUTHERN CALIFORNIA EDISON COMPANY 1995 Internal Cash Flow Projection (Dollars in Thousands) 1994 1995 Actual Projected Net Income After Taxes
$638,531 Dividends Paid
$588,917 Retained Earnings
$49,664 Adjustments:
Depreciation & Decommissioning
$890,656
$847,000 Net Deferred Taxes & ITC
($102,179)
($68,000)
Allowance for Funds Used During Construction
($28,788)
($41,000)
Total Adjustments
$759,689
$738,000 Internal Cash Flow
$809,353 Average Quarterly Cash Flow
$202,338 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, 2, & 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 forecasts earnings or dividends, unless assured confidentiality.
The Net Estimated Cash Flow for 1995 is expected to be comparable to the Actual Cash Flow for 1994.
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K
/X/
Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31, 1994 Commission File Number 1-9936 SCECORP (Exact name of registrant as specified in its charter)
California 95-4137452 (State or other jurisdiction of (I.R.S. Employer incorporation or organization)
Identification No.)
2244 Walnut Grove Avenue (818) 302-2222 Rosemead, California 91770 (Registrant's telephone (Address of principal (Zip Code) number, including area code) executive offices)
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 Exchange)
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 $6,825,040,693 on or about March 20, 1995, based upon prices reported on the New York Stock Exchange. As of March 20, 1995, there were 447,543,652 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, 1994..............
Parts I, II and IV (2) Designated portions of the Joint Proxy Statement relating to registrant's 1995 Annual Meeting of Shareholders.......
Part III
TABLE OF CONTENTS Item Page Part I
- 1.
Business...
1 Business of SCEcorp.
1 Competitive Environment 1
Regulation of SCEcorp 2
Environmental Matters 3
Business of Southern California Edison Company 6
Regulation of Edison.
6 Rate Matters.
7 Fuel Supply 11 Business of The Mission Group and its Subsidiaries 12
- 2.
Properties 14 Existing Utility Generating Facilities.
14 El Paso Electric Company ("El Paso") Bankruptcy 15 Construction Program and Capital Expenditures 16 Nuclear Power Matters 16
- 3.
Legal Proceedings.
18 Antitrust Matters 18 QF Litigation
..18 Environmental Litigation 19 San Onofre Personal Injury Litigation.
20 Employment Discrimination Litigation.
20
- 4.
Submission of Matters to a Vote of Security Holders.
20 Executive Officers of the Registrant.
..20 Part II
- 5.
Market for Registrant's Common Equity and Related Stockholder Matters 26
- 6.
Selected Financial Data 26
- 7.
Management's Discussion and Analysis of Results of Operations and Financial Condition........
26
- 8.
Financial Statements and Supplementary Data....
..26
- 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
..26 Part III
- 10.
Directors and Executive Officers of the Registrant 27
- 11.
Executive Compensation 27
- 12.
Security Ownership of Certain Beneficial Owners and Management...........
..27
- 13.
Certain Relationships and Related Transactions 27 Part IV
- 14.
Exhibits, Financial Statement Schedules, and Reports on Form 8-K.......
- .......................27 Report of Independent Public Accountants on Supplemental Schedules..................
..29 Supplemental Schedules..............
..30 Signatures.....................
..35 Exhibit Index.
36
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"), making financial investments in electric generating facilities and other assets ("Mission First Financial") and managing and selling existing real estate projects ("Mission Land").
SCEcorp is engaged in the business of holding for investment the stock of its subsidiaries.
For the year ended December 31, 1994, Edison and The Mission Group accounted for 88% and 12%, respectively, of the net income of SCEcorp.
During 1994, Edison had an average of 16,351 full-time employees.
The Mission Group and its subsidiaries had 740 full-time employees at December 31, 1994.
SCEcorp had 5 employees at year end 1994.
The principal executive offices of SCEcorp are located at 2244 Walnut Grove Avenue,
- Rosemead, California 91770, and its telephone number is (818) 302-2222.
Competitive Environment Electric utilities operate in a highly regulated environment in which they have an obligation to provide electric service to their customers in return for an exclusive franchise within their service territory. This regulatory environment is changing.
The generation sector has experienced competition from nonutility power producers and Edison expects even greater competition in the generation sector over the next decade.
During 1994, the California Public Utilities Commission ("CPUC") issued a proposal and held several hearings for restructuring California's electric utility industry. Under the proposal, large electric customers would have the option for direct access to a range of generation providers, including utilities, beginning in 1996.
As proposed, eligibility would expand gradually, until all customers, including residential customers, would have the option for direct access to this competitive generation market by 2002.
Edison would continue to provide transmission and distribution service to all customers in its service territory and performance-based regulation would replace existing regulation for such services.
The proposal also stated that utilities should be entitled to recover the portion of their generation investments rendered uneconomic in the new direct access environment.
Edison's response to the CPUC's proposal recommended the creation of a regional competitive market with an independent power pool that would act as the intermediary between all power consumers and suppliers and urged that the CPUC provide that costs previously incurred to serve the state's electricity needs under current regulatory rules be recovered fairly from all customers.
In anticipation of obstacles in implementing the CPUC's proposal due to regulatory, legislative and jurisdictional issues, Edison also recommended the adoption of performance-based ratemaking for its generation operations until direct access phase-in begins.
During the CPUC hearings, Edison stressed that its competitive power market proposal would provide all electric customers with the benefits of a competitive marketplace, reliability and operating efficiency and proposed a schedule for implementing Edison's competitive market plan with customer choice beginning in 1998.
Subsequent to the CPUC proposal, the 1
state legislature passed a resolution requesting that the CPUC withhold implementation of any restructuring plan until its impact can be evaluated by the legislature and governor.
The CPUC issued an interim report to the state legislature on January 24, 1995, describing the positions of the parties and CPUC activities to date, and planned to issue a proposed policy decision for public comment on March 22, 1995.
On March 21, 1995, the CPUC postponed issuance of the proposed policy statement, stating that additional time is necessary for analysis of and reflection on the extensive record developed in the case.
Edison filed a proposal with the CPUC recommending implementation of a competition transition charge
("CTC")
mechanism beginning in 1998, for full recovery of utility investments and obligations incurred to serve customers under the existing regulatory framework. In its filing, Edison estimates its potential transition costs through 2025 to be approximately
$9.3 billion (net present value), based on an assumed 1998 market price of 4 cents per kilowatt-hour.
Of that amount, $4.9 billion would come from Edison's qualifying facility contracts, which are the direct result of legislative and regulatory mandates; $600,000,000 from costs pertaining to certain generating plants; and $3.8 billion from regulatory commitments to be recovered in the future. Such-commitments include deferred taxes, postretirement benefit transition costs, accelerated recovery of nuclear plants, nuclear decommissioning and certain other costs.
At December 31,
- 1994, these commitments included recorded regulatory assets of approximately $1 billion.
Edison currently applies accounting standards that recognize the economic effects of rate regulation.
If rate recovery of generation-related costs becomes.unlikely or uncertain, whether due to competition or regulatory
- action, these accounting standards may no longer apply to Edison's generation operations and the
$1 billion would be a non-cash charge against earnings.
Additionally, Edison may have write-offs associated with its potential transition costs if these costs are not recovered through a CTC or other mechanism.
Until the CPUC establishes more definitive valuation and pricing criteria for its restructuring proposal, including a recovery mechanism for the transition charges, Edison cannot predict the effect of the proposal on its results of operations.
Edison is engaged in an ongoing review of possible responses to the regulatory and competitive changes affecting the electric utility industry, including various corporate, financial, legal and legislative alternatives.
In addition, Edison is seeking to enhance its competitive position by cutting costs and increasing productivity, and by developing new revenue sources.
Mission Energy, one of the nation's largest independent power producers, is well positioned to participate in the changing regulatory environment for electric power.
- Further, international markets present an even greater opportunity for growth and earnings.
Mission Energy currently owns 2,048 megawatts of generating capacity, enough power to serve a population of over 1,500,000.
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.
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SCEcorp is not a public utility under the laws of the State of California and is not subject to regulation as such by the 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.
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 SCEcorp's operation of existing facilities, on the timing,
- cost, location, design, construction and operation by Edison of new facilities required to meet its future load requirements, and on the cost of mitigating the effect of past operations on the environment.
These activities substantially affect future planning and will continue to require modifications of SCEcorp's existing facilities and operating procedures.
SCEcorp is unable to.predict the extent to which additional regulations may affect its operations and capital expenditure requirements.
The Clean Air Act provides the statutory framework to implement a program for achieving national ambient air quality standards in areas exceeding such standards and provides for maintenance of air quality in areas already meeting such standards.
The Clean Air Act was amended in 1990, giving the South Coast Air Quality Management District ("SCAQMD#)
20 years to achieve the federal air quality standards for ozone. The SCAQMD's Air Quality Management Plan ("AQMP"),
adopted in 1994, demonstrates a commitment to attain the federal ozone air quality standard by 2010.
Consistent with the requirements of the AQMP and the Clean Air Act Amendments of 1990 ("CAAA"), the SCAQMD adopted rules to reduce emissions of oxides of nitrogen
("NOx")
from combustion turbines, internal combustion engines, industrial coolers and utility boilers.
On October 15,
- 1993, the SCAQMD adopted the Regional Clean Air Incentives Market
("RECLAIM") which replaces most of the previous rule requirements with a market mechanism for NOx emission trading (trading credits).
RECLAIM
- will, however, require Edison to significantly reduce NOx emissions through retrofit or purchase of trading credits on all basin generation by 2003.
In Ventura County, a NOx rule was adopted requiring more than an 88% NOx reduction by June 1996 at all utility boilers.
Edison expects to spend a total of approximately $290,000,000 in capital expenditures by 2001 to meet these requirements.
Preliminary estimates indicate that certain Mission Energy projects will be required to make capital expenditures of approximately $60,000,000 ($30,000,000 Mission Energy's share) over the next five years in order to comply with the CAAA.
3
The CAAA does 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.
Also, the EPA and Edison will conclude a cooperative tracer study of SO2 emissions from the Mohave plant in 1995.
This study is evaluating potential impact from Mohave emissions on haze within Grand Canyon National Park.
The extent to which these studies may require sulfur dioxide emissions reductions at the Mohave plant is not known.
The acid rain provisions of the amended Clean Air Act also put an annual limit on sulfur dioxide emissions allowed from power plants.
. Edison has received more sulfur dioxide allowances than it requires for its projected operations. As a result of a petition by Mohave County in the State of
- Arizona, the Nevada Department of Environmental Protection
("NDEP")
studied the impact of the plume from the Mohave plant on the Mohave area air quality. The regulatory outcome required Edison to meet a new lower opacity limit in early 1994.
The NDEP will review Edison's performance relative to the opacity limit again in 1995.
The NDEP will consider the implementation schedule for any potential retrofits to meet any revision to the opacity limit in conjunction with an ongoing tracer study being conducted by the EPA to evaluate potential impacts on visibility in the Grand Canyon from sulfur dioxide emissions.
Until more definitive information on tracer study results are available, Edison expects to meet all the present regulations through improved operations at the plant.
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.
Regulations under the Clean Water Act require permits for the discharge of certain pollutants into 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 even more stringent limitations.
In order to comply with guidelines and standards applicable to steam electric power
- plants, Edison incurs additional expenses and capital expenditures.
Edison presently has discharge permits for all applicable facilities.
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.
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 alleged, in part, that San Onofre Units 2 and 3 caused adverse effects to several species of marine life and to the environment.
Based on the MRC findings, the Coastal Commission in 1991 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. Edison is currently in the process of planning and designing these projects, all of which must receive the approval of the Coastal Commission and state and federal resource and regulatory agencies.
Current estimates place Edison's share of these capital costs at about
$83,000,000, which is expected to be spent.over the next 10 to 12 years.
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SCEcorp records its environmental liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated.
SCEcorp reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties.
These estimates include costs for site investigations, remediation, operations and maintenance, monitoring and site closure.
Unless there is a probable amount, SCEcorp records the lower end of this reasonably likely range of costs (classified as other long-term-liabilities at undiscounted amounts).
While SCEcorp has numerous insurance policies that it believes may provide coverage for some of these liabilities, it does not recognize recoveries in its financial statements until they are realized.
At December 31, 1994, SCEcorp's recorded estimated minimum liability to remediate its 61 identified sites was.$114,000,000, compared with
$60,000,000 at the end of 1993.
The increase resulted primarily from changes in estimates for a former pole-treating facility and a fuel-oil tank inspection program.
The ultimate costs to clean up SCEcorp's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as; the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur.
SCEcorp believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $215,000,000. The upper limit of this range of costs was estimated using assumptions least favorable to SCEcorp among a range of reasonably possible outcomes.
SCEcorp expects to clean up its identified sites over a period of up to 30 years.
Remediation costs in each of the next several years are expected to range from $4,000,000 to $8,000,000.
Recorded costs for 1994 were $5,000,000.
One of Edison's sites is a former pole-treating facility; which is considered a federal Superfund site and represents 71% of Edison's recorded liability.
Remedial actions to clean up soil and ground-water contamination that occurred during pole-treating operations (1925-1980) are expected to continue at this site for 30 years.
Rate recovery of environmental-cleanup costs for this site is authorized by the CPUC through an incentive mechanism (discussed below).
SCEcorp's identified sites include several sites for which there is a lack of currently available information including, the nature and magnitude of contamination, and the extent, if
- any, that SCEcorp may be held responsible for contributing to any costs incurred for remediating these sites.
- Thus, no reasonable estimate of cleanup costs can be made for these sites at this time.
SCEcorp's 61 identified-sites include 58-Edison sites.
The CPUC allows Edison to recover environmental-cleanup costs -at 23 of its
- sites, representing $90,000,000 of SCEcorp's recorded liability, through an incentive mechanism (Edison may request to include additional sites).
Under this mechanism, Edison will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs through insurance and other third-party recoveries.
Edison settled an insurance claim with one carrier, and is pursuing additional recovery from several other carriers.
Costs incurred -at Edison's remaining 35 sites are expected to be recovered through customer rates.
Edison has recorded a regulatory asset of $104,000,000 for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.
5
Based on information available at this time, SCEcorp believes it is not likely that it will incur amounts in excess of the upper limit.of the estimated range and, based upon the CPUC's regulatory treatment of environmental-cleanup
- costs, SCEcorp believes that costs ultimately recorded will not have a material adverse effect on its results of operations or financial position.
There can be no assurance,
- however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.
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.
There is an unresolved issue regarding the degree to which coal wastes should be regulated under RCRA.
Increased regulation may result in an increase in expenses related to the operation of Mohave.
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 ("PCB waste').
Current costs for disposal of PCB waste are immaterial.
SCEcorp's capital expenditures for environmental protection for the years 1995 through 1999 are projected to be $1.5 billion. These expenditures are mainly for placing overhead distribution lines underground and reducing nitrogen oxides emissions from gas-fired generators.
Business of Southern California Edison Company Edison was incorporated under California law in 1909.
Edison 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 11 million people.
Edison had an average of 16,351 full-time employees during 1994.
During 1994, 37% of Edison's total operating revenue was derived from commercial customers, 36% from residential customers, 13% from industrial customers, 8% from public authorities, 4% from agricultural and other customers and 2% from resale customers.
Edison comprises the major portion of the assets and revenues of SCEcorp, its parent holding company.
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 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 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 of 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 6
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.
Other federal, state and local laws and regulations relating to environmental protection, land use and water rights also affect Edison.
The California Coastal Commission has continuing jurisdiction over the coastal permit for San Onofre Nuclear Generating Station ('San Onofre')
Units 2 and 3.
Although the units are operating, the permit remains open.
This jurisdiction may continue for several years because it involves oversight of 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, electric sales for export, 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.
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.
Following the revenue requirement phase of a general rate case, Edison and the CPUC proceed to' a rate design phase which allocates revenue requirements and establishes rate levels for customers.
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.
In December 1993, Edison filed an application with the CPUC in which it proposed a performance-based rate-making procedure for recovery of operation and maintenance
('O&M#)
expenses and capital-related costs.
Such costs have traditionally been recovered through general rate cases, attrition proceedings, and cost of capital proceedings.
Edison proposed that the CPUC authorize a base rate revenue indexing formula which would combine O&M and capital-related cost recovery.
In addition, Edison proposed that the period between general rate cases be lengthened from three to six years.
Cost of capital changes would occur, pursuant to a formula, only after significant changes in utility capital markets.
Pursuant to the assigned Commissioner's ruling dated July 12,
- 1994, Edison's performance-base rate-making application was split into two 7
phases.
Phase I was limited to all base rate components of Edison's revenue requirement excluding generation related capital, and operation and maintenance costs.
Edison's amended application for Phase I was filed on August 8, 1994.
Phase II, which addresses generation-related costs, is scheduled to be filed after the CPUC issues a decision in the industry restructuring proceeding.
Edison's fuel, purchased-power and energy-related costs of providing electric service are recovered through a balancing account mechanism called the Energy Cost Adjustment Clause
('ECAC").
Under the ECAC balancing account procedure, actual
- fuel, purchased power and energy-related revenue 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 reasonableness reviews by the CPUC. 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 it would result in an ECAC rate change exceeding 5% of total annual revenue.
For Edison's interest in the three units of the Palo Verde Nuclear Generating Station ("Palo Verde"),
the CPUC authorized a 10-year rate phase-in plan which deferred collection of
$200,000,000 of investment-related revenue during the first four years of operation for each of the three units, commencing on their respective commercial operation dates.
Revenue collection 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 evenly over the final six years.of each unit's phase-in plan.
The plans end in 1996 for Units 1 and 2, and in 1998 for Unit 3.
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 Units is outside a specified range (55% to 80% of each unit's rated capacity).
The Electric Revenue Adjustment Mechanism ("ERAM")
reflects the difference between the recorded and authorized level of base rate revenue.
The CPUC adopted this mechanism primarily to minimize the effect on earnings of fluctuations in retail kilowatt-hour sales.
1995 General Rate Case ("GRC")
On December 27,
- 1993, Edison filed its GRC application with the CPUC proposing a revenue requirement increase of $117,000,000 in Authorized Level of Base Rate Revenues ("ALBRR')
to recover operation and maintenance expenses and capital-related costs for test year 1995.
The CPUC's Division of Ratepayer Advocates
("DRA")
originally recommended a 1995 revenue requirement decrease of $313,500,000 in their March 1994 results of.operations report.
In November 1994, Edison and the DRA filed a Settlement Agreement with the CPUC which resolved major issues associated with Edison's GRC.
The Settlement Agreement will not be fully implemented unless adopted by the CPUC. Specifically, the Settlement Agreement provides for a $67,000,000 revenue decrease in 1995, accelerated eight year recovery of Edison's $2.7 billion remaining investment in San Onofre Units 2
& 3, and a new incentive pricing plan for power generated at San Onofre beginning in 1996.
The pricing plan would replace traditional rate-making treatment for Edison's ongoing operation and maintenance and capital expenses at San 8
Onofre.
The incentive plan would not affect existing rate recovery to decommission San Onofre Units 2
and 3 or the recovery of Edison's investment in Palo Verde.
On December 21, 1994, the CPUC issued an Interim Decision which adopted an interim ALBRR reduction, subject to refund, of $67,305,000 for service rendered on or after January 1, 1995.
On March 3, 1995 the DRA notified the assigned administrative law judge that due to alleged new, "conflicting" information regarding the negotiated price for San Onofre power, the DRA could no longer support the Settlement Agreement as originally submitted to the CPUC.
At a prehearing conference on March 17, 1995 a CPUC administrative law judge set a hearing for March 21, 1995 before the assigned commissioner to hear arguments from parties regarding an attempt by the DRA to withdraw from the Settlement Agreement.
At the March 21, 1995 hearing, the DRA agreed to a
compromise under which they would continue with the settlement, but would be permitted to submit additional testimony concerning the appropriate level of incentive pricing for the San Onofre units, including cost-effectiveness of those units with respect to their recommended pricing level.
Hearings on the settlement are scheduled to start April 3,
- 1995, with a final CPUC decision expected in the third quarter of 1995.
Energy Cost Adjustment Clause In October 1993, the DRA issued its report on qualifying facilities ("QF")
reasonableness issues for the ECAC record period April 1990 through March 1991.
In its
- report, the DRA recommended that the CPUC disallow
$1,574,000 in power purchase expenses incurred as a result of purchases during the record period under a QF contract with Mojave Cogeneration Company, a nonutility generator. In its report, the DRA alleged that in 1988 and 1989, Edison imprudently renegotiated Mojave Cogeneration Company's contract with Edison, resulting in higher ratepayer costs. The DRA further alleged that ratepayers may be harmed in the amount of
$31,600,000 (1993 present value) over the contract's twenty-year life.
The DRA found the execution of five other QF contracts to be reasonable.
Hearings are expected to start no earlier than in the second quarter of 1995.
On September 1, 1992, Edison filed its QF Reasonableness of Operations Report for the period April 1, 1991 through March 31, 1992.
It is presently unknown when or if the DRA will file testimony on the QF reasonableness phase.
On May 28, 1993, Edison filed the non-QF portion of its Reasonableness of Operations Report, which included power purchases and exchanges and the operation of its hydro, coal, gas and nuclear resources for the period April 1,
- 1992, through March 31, 1993.
In February 1994, the DRA recommended:
(1) a $7,200,000 disallowance relating to fuel oil inventory management; and (2) a
$5,000,000 adjustment for transmission loss revenues.
Edison agreed with the DRA's recommended adjustment for transmission loss revenues and in July 1994 credited the ECAC balancing account $8,300,000 for the period April 1,
- 1992, through December 31,
- 1994, plus interest.
In December 1994, the DRA reduced its proposed disallowance related to fuel oil inventory management to $4,500,000. On March 16, 1995, the DRA withdrew its disallowance recommendation related to fuel oil inventory management.
Hearings on this matter have been taken off calendar and a final CPUC decision is expected in the third quarter of 1995.
Edison filed its QF Reasonableness of Operations Report for the period April 1,
- 1992, through March 31,
- 1993, on September 1,
1993.
It is presently unknown when or if the DRA will file testimony in the QF reasonableness phase.
9
On May 27, 1994, Edison requested a $312,300,000 annual rate increase for service beginning January 1,
- 1995, for changes to the ECAC,
- ERAM, Low Income Surcharge and base rate levels. When combined with other revenue changes effective January 1, 1995, the consolidated rate increase for 1995 was expected to be $503,800,000.
Therefore, Edison.made a rate stabilization proposal which would limit the January 1,
- 1995, rate increase to $291,200,000 (3.9%)
by deferring recovery of approximately
$212,600,000 of 1995 fuel and purchased-power expenses until 1996.
in July 1994, Edison updated its ECAC request to a $352,300,000 increase with a deferral of approximately $242,800,000 to keep the January 1, 1995, rate increase at $291,200,000 (3.9%).
The DRA originally proposed a rate increase of $261,400,000 (3.5%) and later proposed that recovery of the amount in the ECAC balancing account (estimated by the DRA to be
$166,000,000) be deferred regardless of the resultant rate change on January 1, 1995.. Other parties recommended that no-revenue increase be allowed in 1995.
On December 21, 1994, the CPUC issued its decision adopting a revenue increase of $223,700,000.
When combined with other revenue changes occurring January 1,
- 1995, the total combined revenue increase was $192,672,000 without deferred recovery of fuel and purchased power expenses.
Edison filed its QF Reasonableness of Operations Report on May 27, 1994 for the period April 1, 1993 through March 31, 1994.
It is presently unknown when or if the DRA will file testimony on the QF reasonableness phase.
CPUC-Mandated Power Contracts In 1989, the CPUC initiated a competitive bidding process known as. the Biennial Resource Plan Update
("BRPU").
The CPUC directed Edison to solicit bids for 624 MW from QFs, a category of independent power producers.
Edison issued its bid solicitation in August 1993.
On December 9,
- 1993, Edison suspended the BRPU solicitation due to the discovery of a bid anomaly that raised prices above those allowed by the rules of the solicitation. Based on bid protocol, the BRPU solicitation would require Edison to purchase 686 MW of new capacity at fixed prices starting in 1997.
This would cost Edison's customers $14 billion over the lives of the contracts.
Edison requested the CPUC to cancel the BRPU solicitation because it:
- 1) required payments above Edison's avoided cost,
- 2) required Edison to purchase capacity before it is needed in 2005, and
- 3) dramatically increased stranded cost in a soon-to-be restructured electric utility industry.
Before the CPUC rendered a final decision regarding the BRPU solicitation, Edison diligently pursued negotiations with "winning" bidders (i.e.,
those whose bids would have qualified them to obtain a contract but for Edison's appeals for cancellation of the process).
The purpose of these negotiations was to develop alternative agreements that would be significantly less costly than those mandated by the solicitation.
Edison reached agreement with seven QFs representing 627 MW of the 686 MW mandated in the solicitation.
These alternative agreements would save Edison customers about 80% of anticipated overpayments associated with contracts from the CPUC-mandated solicitation.
All of the, alternative agreements are subject to CPUC approval.
On December 21, 1994, the CPUC issued its final decision to proceed with the BRPU solicitation.
On January 6,
- 1995, Edison appealed the CPUC decision to FERC.
On February 23,
- 1995, FERC ruled that the BRPU solicitation violated the Public Utility Regulatory Policies Act ("PURPA")
and the FERC's regulations because the CPUC did not consider all potential sources of capacity in reaching its avoided cost determination.
The FERC decision therefore concluded that Edison cannot lawfully be compelled to enter into the.BRPU contracts.
In light of the FERC decision, the CPUC has stayed the BRPU proceeding until May 10, 1995.
10
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 returned to service on December 30,
- 1989, and Unit 1 was returned to service on July 5, 1990.
In November 1991, the DRA issued a report recommending disallowances totaling more than $160,000,000, including a $63,000,000 disallowance for revenue collected during the outages (including interest).
In September 1993, Edison and the DRA agreed to settle these disputes for
$38,000,000 (including $29,000,000 for replacement power costs, $2,000,000 for capital projects and approximately $7,000,000 for interest), subject to CPUC approval.
The settlement resolves all issues related to the 1989 1990 outages at Palo Verde. The effect of the settlement has been fully reflected in the financial statements.
A CPUC decision is expected by mid-1995.
Mohave Order Instituting Investigation ("011")
In April 1986, the CPUC began investigating the 1985 rupture of a high pressure steam pipe at the Mohave Generating Station ("Mohave").
Edison is plant operator and 56% owner.
The CPUC's 011 reviewed Edison's share of repair costs and replacement fuel and energy-related costs associated with the outage.
Edison incurred costs of approximately $90,000,000 (including interest) to repair damage from the accident and provide replacement power during the six-month outage.
This total is net of Edison's recovery of expenses from the settlement of lawsuits with contractors and insurance recoveries.
In March
- 1994, the CPUC issued a decision finding that Edison acted unreasonably in failing to implement an inspection program.
The CPUC decision ordered a second phase of this proceeding to quantify the disallowance. Edison believes the final outcome of this matter will not materially affect its results of operations.
Fuel Supply Fuel and purchased-power costs amounted to approximately $3.4 billion in 1994, a 3% increase over 1993.
Edison's sources of energy during 1994 were: purchased power 36%; natural gas 26%; nuclear 21%; coal 13%; and hydro 4%.
Average fuel costs, expressed in cents per kilowatt-hour, for the year ended December 31,
- 1994, were:
oil, 6.034 cents; natural gas, 2.462 cents; nuclear, 0.513 cents; and coal, 1.280 cents.
Natural Gas Supply Twelve of Edison's major steam electric generating plants are designed to burn oil or natural gas as a primary boiler fuel.
In 1990, Edison adopted an all-gas strategy to comply with air quality goals by eliminating burning oil in all but very extreme conditions.
In August 1991, the CPUC adopted regulations which made Edison fully responsible for all natural gas procurement activities previously performed by local distribution companies.
To implement its all-gas strategy, Edison acquired a balanced portfolio of gas supply and transportation arrangements.
Traditionally, natural gas needs in southern California were met from gas production in the southwest region of the country. To diversify its gas supply, Edison entered into four 15-year natural gas supply agreements with major producers in western 11
Canada. These contracts, totaling 200,000,000 cubic feet per day, have market-sensitive pricing arrangements.
This represents about 40% of Edison's current average annual supply needs.
The rest of Edison's gas supply is acquired under short-term contracts from Texas, New Mexico and the Rocky Mountain region.
Firm transportation arrangements provide the necessary long-term reliability for supply deliverability.
To transport Canadian supplies, Edison contracted for 200,000,000 cubic feet per day of firm transportation arrangements on the Pacific Gas Transmission and Pacific Gas & Electric Expansion Project connecting southern California to the low-cost gas producing regions of western Canada.
Edison has a 30-year commitment to this project, construction of which was completed in late 1993.
In addition, Edison has a 15-year commitment with El Paso Natural Gas to transport 200,000,000 cubic feet per day (option to step down to 130,000,000 cubic feet per day in 1997) from the southwestern U.S.
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 2& 3 Uranium concentrates(1) 1995 Conversion 1995 Enrichment 1998 Fabrication 2000 Spent fuel storage(2) 2005/2003 (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 the units, including interpool transfers and maintaining full-core reserve.
To supplement existing spent fuel storage, a contingency plan is being developed to construct additional on-site storage capacity with initial operation scheduled for no later than 2002.
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.
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, enrichment, and fabrication services cover requirements through 1998, 2002, and 2000, respectively.
Palo Verde on-site spent fuel storage capacity will accommodate needs through 2005 for Units 1 and 2 and 2006 for Unit 3, while maintaining full-core reserve.
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, Mission First Financial and Mission Land. The businesses of these companies are described below. For SCEcorp's business segment information for each of the years ended December 31, 1994, 1993 and 1992, see Note 12 of "Notes to Consolidated Financial Statements" contained in the 1994 Annual Report to shareholders incorporated by reference in this report.
12
On December 31, 1994, The Mission Group had consolidated assets of $4.2 billion and, for the year then ended, had consolidated operating revenue of $546,000,000 and consolidated net income of $88,000,000.
The Mission Group's principal executive offices are located at 18101 Von Karman Avenue, #1700, Irvine, California 92715.
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,
- 1994, Mission Energy subsidiaries held interests in 34 operating power production facilities with an aggregate power production capability of 4,479 MW, of which 2,048 MW are attributable to Mission Energy's interests.
These operating facilities are located in California, Nevada, New Jersey, Pennsylvania,
- Virginia, Washington, Australia,
- Spain, and the United Kingdom.
In addition, facilities aggregating more than 1,362 MW, of which one 500 MW facility is located in Australia, 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, California and offshore Louisiana.
In February 1994, Mission Energy --
as lead developer --
and its partners, General Electric Capital Corporation, Mitsui & Co.,
Ltd.
and P.T.
Batu Hitam Perkasa, signed a 30-year power-purchase agreement with the Indonesian government for the 1,230-MW Paiton project.
At December 31, 1994, Mission Energy had total consolidated assets of $2.8 billion and for the year then ended, had consolidated operating revenue of $381,000,000 and consolidated net income of $55,000,000.
Currently, most of Mission Energy's operating power production facilities have QF status under PURPA and the regulations promulgated thereunder.
QF status exempts the projects from the application of the HoldingCompany
- 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 ownership interests in two operating power projects that have received exempt wholesale generator status as defined in 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 QF 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 First Financial.
Mission First Financial participates in investment opportunities involving leveraged leasing, project financing, affordable housing and cash management.
Its investments include interests in nuclear power, cogeneration, waste-to-energy, hydroelectric, electric transportation and affordable housing facilities. Since its inception in 1987, Mission First Financial has invested in over 100 projects.
In 1994, Mission First Financial invested $45,000,000 for a 26% interest in a
powerplant sale/leaseback with EPZ, the largest generating company in the Netherlands.
The facility, which has a total cost of $1.27 billion, will be operated by EPZ during the 22-year term of the lease.
During the year, Mission First Financial invested $74,000,000 in new affordable housing projects and has committed to invest nearly $95,000,000 in projects to be completed in the next two years.
In addition, the Company expanded its participation in this business segment by arranging and selling an interest in a number of affordable housing projects for
$48,000,000.
13
At December 31,
- 1994, Mission First Financial had total consolidated assets of $1.0 billion and, for the year then ended, consolidated operating revenue of $34,100,000 (including interest and other income) and consolidated net income of $32,700,000.
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 California.
Mission Land and its subsidiaries also have interests in industrial, residential and commercial real estate in Texas,
SCEcorp is exiting the real estate business in an orderly fashion over time.
At December 31,
- 1994, Mission Land had total consolidated. assets of
$382,700,000 and for the year then ended, consolidated operating revenue of $153,400,000 and consolidated net income of $107,000. Since deciding to exit the real estate business in late 1991, Mission Land has: reduced assets by one-third, primarily through asset sales; reduced debt significantly; improved operating income through higher occupancy rates and lower operating costs and increased real estate reserves.
As a
- result, Mission Land believes it has improved its ability to systematically exit the real estate business in a self-sustaining way.
However, Mission Land may experience additional losses if the real estate market should deteriorate.
Item 2. Properties Existing Utility Generating Facilities Edison owns and operates 12 oil-and gas-fueled electric generating plants, one diesel-fueled generating plant, 38 hydroelectric plants 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. Edison owns 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.
Palo Verde and the Four Corners Project 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.
At year-end 1994, the existing Edison-owned generating capacity (summer effective rating) was comprised of approximately 66% gas, 14% nuclear, 11%
coal, 8% hydroelectric and 1% oil.
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 1,156 MW and located in whole or in part on lands of the U.S.,
are owned and operated by Edison under governmental licenses which expire at various times between 1995 and 2022.
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 14
under terms and conditions less favorable than those of the expired licenses.
Edison's applications for the relicensing of certain hydroelectric projects referred to above with an aggregate effective operating capacity of 89.0 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 are issued.
In 1994, Edison's peak demand was 18,044 MW, set on August 12, 1994.
Total area system operating capacity of 20,615 MW was available to Edison at the time of the 1994 peak. Edison's record peak demand of 18,413 MW occurred on August 17, 1992.
Substantially all of Edison's properties are subject to the lien of a trust indenture securing First and Refunding Mortgage Bonds
("Trust Indenture"),
of which approximately $4.5 billion principal amount was outstanding at December 31, 1994.
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 the Trust Indenture.
In addition, such lien 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 Nation of Indians under an easement from the United States and a lease from The Navajo Nation, 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 Nation, the possible inability of Edison to resort to legal process to enforce its rights against The Navajo Nation without Congressional consent, possible impairment or termination under certain circumstances of the easement and lease by The Navajo Nation, Congress or the Secretary of the Interior and the possible invalidity of the Trust Indenture lien against Edison's interest in the easement, lease and improvements on the Four Corners Project.
El Paso Electric Company ("El Paso") Bankruptcy El Paso owns and leases a combined 15.8% interest in Palo Verde and owns a 7% interest in Units 4 and 5 of the Four Corners Project.
In January 1992, El Paso filed a voluntary petition to reorganize under Chapter 11 of the Bankruptcy Code in the United States Bankruptcy Court for the Western District of Texas.
Pursuant to an agreement among the Palo Verde participants 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, respectively.
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.
In February 1992, the bankruptcy court approved a stipulation between El Paso and Arizona Public Service
("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.
15
On August 27,
- 1993, El Paso filed with the bankruptcy court an Amended Plan of Reorganization and Disclosure Statement ('Amended Plan").
The Amended
- Plan, which is subject to numerous conditions, proposes a
reorganization pursuant to which El Paso will become a wholly-owned subsidiary of Central and South West Corporation. The Amended Plan also
- proposes, among other things, (i) rejection of the El Paso leases and reacquisition by El Paso of the Palo Verde interests represented by the
- leases, and (ii)
El Paso's assumption of the Four Corners Operating Agreement and the Arizona Nuclear Power Project Participation Agreement.
On November 19, 1993, the bankruptcy court approved a Cure and Assumption Agreement among El Paso and the Palo Verde Participants, in which El Paso shall (i) assume the Participation Agreement on the date the Amended Plan becomes effective, and (ii) cure its pre-petition default on the date the court approves the Order. Confirming El Paso's Amended Plan.
On December 8, 1993, the bankruptcy court confirmed El Paso's Amended Plan.
Effectiveness of the Amended Plan is still subject to approval by numerous state and federal agencies.
El Paso estimates that it will take about 18 months from the date the Amended Plan was confirmed to obtain all necessary regulatory approvals.
Construction Program and Capital Expenditures Cash required by SCEcorp for its capital expenditures totaled $1.1 billion in
- 1994,
$1.3 billion in 1993 and $1.2 billion in 1992.
Construction expenditures for the 1995-1999 period are forecasted at- $4.9 billion.
In addition to cash required for construction expenditures for the next five years as discussed above, $1.8 billion is needed to meet requirements for long-term debt maturities and sinking fund redemption requirements.
SCEcorp's estimates of cash available for operations for the five years through 1999 assume, among other things, Edison's receipt of adequate and timely rate relief and the realization of its assumptions regarding cost increases, including the cost of capital.
SCEcorp'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 Edison's nuclear facilities have been reliable sources of inexpensive, non-polluting power for Edison's customers for more than a decade.
Throughout the operating life of these facilities, Edison's customers have supported the revenue requirements of Edison's capital investment in these facilities and for their incremental costs through traditional cost-of service ratemaking.
Under the terms of the Settlement Agreement, discussed above under the heading '1995 General Rate Case',
Edison would recover its remaining investment in San Onofre Units 2 and 3 on an accelerated basis during the eight-year period from February 1, 1996, through December 31, 2003.
In addition, the traditional cost-of-service ratemaking for San Onofre Units 2 and 3 would be superseded by incremental cost incentive pricing, in which Edison's customers would pay a preset price for each kilowatt-hour of energy generated at San Onofre during the eight-year period. Edison would be compensated for the incremental costs required for the continued operation of San Onofre Units 2 and 3 only with revenues earned through the incremental cost incentive pricing.
However, Edison would also retain the ability to request recovery of the cost of fuel consumed for generation of replacement energy for periods in which San Onofre is not generating power through future ECAC filings.
Edison would also continue 16
to collect funds for decommissioning expenses through traditional ratemaking treatment.
In addition, Edison would continue to receive traditional cost-of-service ratemaking for its share of Palo Verde Units 1, 2, and 3 under the terms of the Settlement Agreement.
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 November 1992, Edison discontinued operation of San Onofre Unit 1.
Edison will recover its investment, earning an 8.98% rate of return, by August 1996.
The agreement does not affect Unit l's decommissioning, scheduled to start in 2013.
The estimated current-dollar decommissioning costs for Unit 1 have been recorded as a liability.
Palo Verde Nuclear Generating Station On March 14, 1993, APS, as operating agent, manually shut down Palo Verde Unit 2 as a result of a steam generator tube leak. Unit 2 remained shut down and began its scheduled refueling outage on March 19, 1993.
An extensive inspection of the Palo Verde Unit 2 steam generators was performed prior to the unit's return to service on September 1, 1993.
APS determined that intergranular attack/intergranular stress corrosion cracking was a major contributor to the tube leak.
APS is continuing its evaluation of the effects of possible steam generator tube degradation in all three units (six steam generators) and has instituted several avenues of study and corrective action.
Palo Verde Units 1, 2 and 3 operated at reduced power (85%) until the investigation and other associated activities were completed.;
APS returned all three units to full power in August 1994 after implementing corrective measures.
Nuclear Facility Decommissioning Edison's costs to decommission its nuclear generation facilities is estimated to be $1.7 billion in 1994 dollars.
Decommissioning is scheduled to begin in 2013 at San Onofre and 2024 at Palo Verde.
Edison is currently collecting $104,381,000 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.
As of December 31,
- 1994, Edison's decommissioning trust funds totaled approximately $919,000,000 (market value).
Nuclear Facility Delpreciation In October 1994, the CPUC authorized Edison to accelerate recovery of its nuclear plant investments by $75,000,000 per year through 2011, with a corresponding deceleration in recovery of its transmission and distribution assets through revised depreciation estimates over their remaining useful lives.
Nuclear Insurance Edison carries the maximum insurance coverage available to protect against.
losses from damage to its nuclear units and to provide some of its replacement energy costs in the unlikely event of an accident at any of its nuclear units.
A description of this insurance is included in Note 17
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 NRC action to suspend operation of the damaged unit.
Further, 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.
Item 3. Legal Proceedings Antitrust Matters Transphase Systems, Inc.,
filed a lawsuit on May 3,
- 1993, in the U.S.
District Court for the Central District of California against Edison and San Diego Gas & Electric Company ("SDG&E#).
Transphase alleged that the utilities willfully acquired and maintain monopoly.power in the energy conservation industry, and that Transphase is competitively disadvantaged because it cannot directly access the DSM funds Edison collects from its ratepayers to fund DSM activities.
The complaint sought $50,000,000 in damages before trebling.
On October 7,
- 1993, the U.S.
District Court dismissed Transphase's complaint with prejudice on three separate grounds.
Transphase appealed the District Court's order to the Ninth Circuit Court of Appeals. The Ninth Circuit denied Transphase's appeal and request for a hearing en banc.
On September 1, 1994, Transphase filed a petition for a writ of certiorari with the U.S. Supreme Court. The Supreme Court denied the writ on October 31, 1994.
QF Litigation On May 20, 1993, four geothermal QFs filed a lawsuit against Edison in Los Angeles County Superior Court, claiming that Edison underpaid, and continues to underpay, the plaintiffs for energy.
Edison denied the allegations in its response to the complaint. The action was brought on behalf of Vulcan/BN Geothermal Power Company, Elmore L.P., Del Ranch L.P.,
and Leathers L.P.,
each of which is partially, owned by a subsidiary of Mission Energy Company (a subsidiary of SCEcorp).
In October 1994, plaintiffs submitted an amended complaint to the court to add causes of action for unfair competition and restraint of trade.
The plaintiffs allege that the underpayments totaled at least $21,000,000 as of the filing of the amended complaint.
In other court filings, plaintiffs contend that additional contract payments owing through the end of the contract term could total approximately $60,000,000.
They also seek treble damages for the alleged restraint of trade violations, unspecified punitive damages, and an injunction to enjoin Edison from "future" unfair competition. On February 9, 1995, the court sustained some of Edison's demurrers to plaintiffs first amended complaint and overruled others.
The Court also granted plaintiffs 30 days in which to amend their complaint further.
On or about March 9, 1995, plaintiffs filed a second amended complaint, realleging the substance of the claims included in the first amended complaint.
The materiality of a judgment in favor of the plaintiffs would be largely dependent on the extent to which additional payments resulting from such a judgment are recoverable through Edison's ECAC.
Between January.1994 and October 1994, Edison was named as a defendant in a series of eight lawsuits brought by independent power producers of wind generation.
Seven of the lawsuits were filed in Los Angeles County Superior Court and one was filed in Kern County Superior Court.
The lawsuits allege Edison incorrectly interpreted contracts with the plaintiffs by limiting fixed energy payments to a single 10-year period rather than beginning a new,10-year period of fixed energy payments for each stage of development.
In its responses to the complaints, Edison denied the plaintiffs' allegations.
In each of the lawsuits, the plaintiffs seek declaratory relief regarding the proper interpretation of 18
the contracts.
Plaintiffs allege a combined total of approximately
$189,000,000 in damages, which includes consequential damages claimed in seven of the eight lawsuits.
On March 1, 1995, the court in the lead Los Angeles Superior Court case granted the plaintiffs' motion seeking summary adjudication that the contract language in question is not reasonably susceptible to Edison's position that there is only a single, 10-year period of fixed payments.
On March 8, 1995, the court in the Kern County Superior Court case directed Edison to submit a proposed order that would deny a similar summary adjudication motion brought by the plaintiff in that case.
Edison believes the March 1 ruling in the Los Angeles case is erroneous and has asked the court to reconsider its ruling.
If the court declines to do so, Edison intends to seek the earliest possible appellate review of the March 1 ruling.
Following the March 1 ruling, an eighth lawsuit was filed in the Los Angeles Superior Court raising claims similar to those alleged in the first seven.
Edison intends to respond to the complaint in the new lawsuit by denying its material allegations.
The materiality of final judgments in favor of the plaintiffs would be largely dependent on the extent to which any damages or additional payments which might result from such judgments would be recoverable through Edison's ECAC.
Environmental Litigation California Department of Toxic Substances Control ("DTSC") Report of Violation On September 23,
- 1993, DTSC issued a Report of Violation to Edison, alleging various hazardous waste violations of the California Health &
Safety Code at several Edison facilities.
Edison has settled the matter with DTSC for an amount of $1,950,000.
Of the $1,950,000, approximately
$700,000 will be paid to other parties and allocated toward various educational programs. As an additional component of the settlement, the parties will negotiate a fee for service agreement to fund DTSC permitting and oversight costs.
The total amount of those costs is estimated.to be
$1,500,000 to $2,000,000, which would be spread out over several years.
Electric and Magnetic Fields ("EMF")
Edison has been served with two lawsuits, both of which allege, among other things, that certain plaintiffs developed cancer as a result of EMF emitted from Edison facilities.
The lawsuits, filed in Orange County Superior Court and served on Edison in June 1994 and January 1995, request compensatory and punitive damages. Although no specific damage amounts are alleged in the complaints, in subsequent court filings, plaintiffs estimated general and compensatory damages of $8,000,000 and $13,500,000, plus unspecified punitive damages.
In August 1994, one of the co defendants in the June 1994 action filed a cross-complaint against the other co-defendants, including Edison, requesting indemnification and declaratory relief concerning the rights and responsibilities of the parties.
A third lawsuit was filed in Los Angeles County Superior Court and served on Edison in July 1994.
The complaint requested an unspecified amount for compensatory damages allegedly arising out of exposure to EMF emitted from Edison facilities.
On February 7,
- 1995, Edison's demurrer to the plaintiffs' complaint was sustained without leave to amend.
The plaintiffs have waived their right to appeal and this matter has been concluded.
A fourth case, was filed in Orange County Superior Court and served on Edison in March 1995.
The complaint seeks an unspecified amount of compensatory and punitive damages.
The plaintiff alleges, among other things, that he developed cancer as a result of EMF emitted from Edison facilities which he alleges were not constructed in accordance with CPUC standards.
19
0 Edison believes that there is no proven scientific basis for the allegation that EMF is hazardous to health and, therefore, believes that the EMF lawsuits described above are without merit.
San Onofre Personal Injury Litigation An engineer for two contractors providing services for San Onofre has been diagnosed with leukemia.
On July 12, 1994, the engineer and his wife sued Edison, SDG&E and the manufacturer of the fuel rods for the plant in the United States District Court for the Southern District of California.
The plaintiffs allege that the engineer's illness resulted from contact with radioactive fuel particles released from failed fuel rods.
Plant records show that the engineer's exposure to radiation was well below NRC safety levels.
In the complaint, plaintiffs seek unspecified compensatory and punitive damages.
In its response to the complaint, Edison denies plaintiffs' allegations.
A pretrial conference is scheduled for May 1995, to set a trial date.
An Edison engineer employed at San Onofre died in 1991 from cancer of the abdomen.
On February 6, 1995, his children sued Edison, SDG&E and the manufacturer of the fuel rods for the plant in the United States District Court for the Southern District of California.
The plaintiffs allege that the engineer's illness resulted from, and was aggravated by, exposure to radiation at San Onofre, including contact with radioactive fuel particles released from failed fuel rods.
Plant records show that the engineer's exposure to radiation was well below NRC safety levels.
In the complaint, plaintiffs seek unspecified compensatory and punitive damages.
Edison denies plaintiffs' allegations and is vigorously defending this action.
Employment Discrimination Litigation On September 21, 1994, nine African-American employees filed a lawsuit against SCEcorp and Edison on behalf of an alleged class of African-*
American employees, alleging racial discrimination in job advancement, pay, training and evaluation.
The lawsuit was filed in the United States District Court for the Central District of California.
The plaintiffs seek injunctive relief, as well as an unspecified amount of compensatory and punitive damages, attorneys' fees, costs and interest.
SCEcorp and Edison have responded by denying the material allegations of the complaint and asserting several affirmative defenses.
The parties are engaged in discovery, and no trial date has been set.
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 I:
Executive Officers of the Registrant (1)
SCEcorp Age at December Effective Executive Officer 31, 1994 Company Position Date John E. Bryson 51 Chairman of the Board, Chief Executive October 1, 1990 Officer and Director Bryant C. Danner 57 Senior Vice President and GeneraL JuLy 1, 1992 CounseL Alan J. Fohrer 44 Senior Vice President, Treasurer and January 21, 1993 Chief FinanciaL Officer 20
Richard K. Bushey 54 Vice President and Controller July 21, 1988 Kenneth S. Stewart 43 Assistant General Counsel November 19, 1992 and Corporate Secretary The Executive Officers of SCEcorp include the Chairman of the Board and Chief Executive Officer, the elected Vice Presidents and the Secretary of SCEcorp and Edison as well as the Chief Executive Officers and Presidents, Executive Vice Presidents and Senior Vice Presidents of Mission Energy, Mission Financial, and Mission Land (collectively 'The Mission Companies") all of whom may be deemed policy makers of SCEcorp.
None of SCEcorp's elected executive officers are related to each other by blood or marriage. As set forth in Article IV of SCEcorp's Bylaws, the elected 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 elected executive officers of SCEcorp holds an identical position with Edison except for Alan J. Fohrer, who does not hold the Treasurer position at Edison.
Each of the elected executive officers of SCEcorp has been actively engaged in the business of Edison for more than five years except for Bryant C. Danner.
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 Chief May 1988 to Financial Officer of SCEcorp September 1990 Executive Vice President and January 1985 to Chief Financial Officer of Edison September 1990 Bryant C. Danner Partner with Law firm of Latham & Watkins(1)(2)
January 1970 to June 1992 Alan J. Fohrer Vice President, Treasurer and Chief April 1991 to Financial Officer of SCEcorp and Edison January 1993 Assistant Treasurer of SCEcorp July 1988 to March 1991 Assistant Treasurer and Manager of Cost September 1987 Control of Edison to March 1991 Kenneth S. Stewart Assistant General Counsel of Edison March 1992 to and SCEcorp October 1992 Senior Counsel of Edison March 1989 to February 1992 Prior to leaving the law firm of Latham & Watkins, Bryant C. Danner was in the firm's environmental department.
(2) This entity is not a parent, subsidiary or other affiliate of Edison.
Edison Age at Deceuber Effective Executive Officer 31, 1994 Company Positionl)
Date John E. Bryson 51 Chairman of the Board, Chief October 1, 1990 Executive Officer and Director Bryant C. Danner 57 Senior Vice President and July 1, 1992 General Counsel Alan J. Fohrer 44 Senior Vice President and June 17, 1993 Chief Financial Officer Harold B. Ray 54 Senior Vice President (Power Systems)
June 1, 1990 Owens F. Alexander, Jr.
45 Vice President (Marketing)
April 4, 1994 Robert H. Bridenbecker 51 Vice President (Customer Solutions)
June 1, 1990 21
Vikram S. Budhraja 47 Vice President (Planning February 1, 1992 and Technology)
Richard K. Bushey 54 Vice President and Controller January 1, 1984 Ronald Daniels 55 Vice President (Regulatory Projects)
August 10, 1992 John R. Fielder 49 Vice President (Regulatory Policy and February 1, 1992 Affairs)
Bruce C. Foster 42 Vice President (Regulatory Affairs)
January 1, 1995 Robert G. Foster 47 Vice President (Public Affairs)
November 18, 1993 Lawrence D. Hamlin 50 Vice President (Power Production)
February 1, 1992 Margaret H. Jordan 51 Vice President (Health Care and December 7, 1992 Employee Services)
Russell W. Krieger 46 Vice President (Nuclear Generation)
June 17, 1993 J. Michael Mendez 53 Vice President (Regional Leadership)
February 8, 1993 C. Alex Miller 37 Vice President and Treasurer January 1, 1995 Georgia R. Nelson 44 Vice President (Performance Support)
March 18, 1993 Richard M. Rosenblum 44 Vice President (Engineering and June 17, 1993 Technical Services)
Kenneth S. Stewart 43 Assistant.General Counsel November 19, 1992 and Corporate Secretary Effective October 31, 1994, Lewis M. Phelps resigned from his position as Vice President (Corporate Communications) of Edison.
(2)
John E.
- Bryson, Bryant C. Danner, Richard K.
Bushey and Kenneth S.
Stewart hold the same positions with SCEcorp.
Alan J. Fohrer holds the office of Senior Vice President, Treasurer and Chief Financial Officer of SCEcorp. SCEcorp is the parent holding company of Edison.
None of Edison's executive officers are related to each other by blood or marriage.
As set forth in Article IV of Edison's Bylaws, the officers of Edison are chosen annually by and serve at the pleasure of Edison's Board of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected.
All of the executive officers have been actively engaged in the business of Edison for more than five years except for Bryant C. Danner, Owens F. Alexander, Jr., Bruce C. Foster and Margaret H. Jordan.
Those officers who have not held their present position for the past five years had the following business experience during that period:
John E. Bryson Executive Vice President January 1985 to and Chief Financial Officer September 1990 Bryant C. Danner Partner with Law Firm of January 1970 to Latham & Watkinso'1
- 3)
June 1992 Alan J. Fohrer Senior Vice President, Treasurer and January 1993 to Chief Financial Officer May 1993 Vice President, Treasurer and April 1991 to Chief Financial Officer January 1993 Assistant Treasurer and Manager -- Cost Control September 1987 to March 1991 Harold B. Ray Vice President -- Nuclear Engineering August 1989 Safety and Licensing to May 1990 Owens F. Alexander, Jr.
South Central Bell and January 1989 to BellSouth Telecommunications March 1994 in Atlanta, Georgia Marketing Group Quality Director --
September 1991 to February 1994 General Manager Customer Service --
March 1991 to August 1991 General Manager Business Marketing October 1988 to February 1991 22
0I Robert H. Bridenbecker Vice President and Site Manager --
September 1989 to San Onofre Nuclear Generating Station May 1990 Vikram S. Budhraja Vice President -- System Planning April 1991 to and Fuel Supply January 1992 Manager -- Electric System Planning September 1986 to March 1991 Ronald Daniels Vice President Revenue Requirements August 1989 to July 1992 John R. Fielder Vice President --
Information Services January 1989 to January 1992 Bruce C. Foster Regional. Vice President (San Francisco Office)
January 1992 to December 1994 Vice President--New England Electric January 1990 to December 1991 Robert G. Foster Regional Vice President (Sacramento Office)
January 1988 to October 1993 Lawrence D. Hamlin Manager --
Steam Generation April 1990 to January 1992 Manager -- Research, System Planning September 1986 and Research Department to April 1990 Margaret H. Jordan Vice President -- Kaiser Foundation March 1986 to Health Plan of Texas(2 )
3 )
December 1992 Russell W. Krieger Station Manager,(San Onofre)
August 1990 to May 1993 Station Operation Manager (San Onofre)
August 1985 to July 1990 J. Michael Mendez Vice President -- Human Resources August 1991 to February 1993 Division Vice President -- Customer Service January 1991 to July 1991 Division Manager -- Customer Service September 1989 to January 1991 C. Alex Miller Treasurer June 1993 to January 1995 Assistant Treasurer April 1991 to May 1993 Manager of Financial Planning and September 1987 to Regulatory Finance March 1991 Georgia R. Nelson Special Assistant to the Chairman February 1992 to March 1993 Manager -- Procurement and September 1989 to Material Management January 1992 Richard M. Rosenblum Manager of Nuclear Regulatory Affairs June 1989 to May 1993 Kenneth S. Stewart Assistant General Counsel March 1992 to November 1992 Senior Counsel March 1989 to February 1992 Prior to leaving the law firm of Latham & Watkins, Bryant C. Danner was in the firm's environmental department.
(2) As Vice President of the Kaiser Foundation Health Plan of Texas, Margaret H. Jordan was responsible for serving over 124,000 members in 10 multispecialty medical offices in the Dallas/Fort Worth area.
This entity is not a parent, subsidiary or other affiliate of Edison.
23
0 The Mission Companies Age at December Effective Executive Officer 31, 1994 Capany Position1 (2)
Date John E. Bryson 51 Chairman of the Board -- Mission Energy May 20, 1993 Alan J. Fohrer 44 Vice Chairman of the Board -- Mission Energy May 20, 1993 Edward R. Mutter 42 President and Chief Executive August 23, 1993 Officer -- Mission Energy Robert M. EdgeLL 47 Executive Vice President -- Mission Energy April 1, 1988 Robert Dietch 56 Senior Vice President -- Mission Energy February 1, 1992 James V. laco, Jr.
50 Senior Vice President and Chief January 17, 1994 Financial Officer -- Mission Energy S. Daniel Melita 43 Senior Vice President -- Mission Energy November 1, 1993 S. Linn Williams 48 Senior Vice President and General Counsel November 11, 1994
-- Mission Energy Thomas R. McDaniel 45 President and Chief Executive March 1, 1992 Officer -- Mission First Financial and Mission Land Lawrence W. Yu 41 Executive Vice President October 15, 1993
-- Mission First Financial Charles W. Johnson 48 Executive Vice President -- Mission Land August 7, 1992 Alan J.
Fohrer served as interim Vice Chairman and interim Chief Executive Officer of Mission Energy prior to Edward R.
Muller's appointment as President and Chief Executive Officer.
Alan M. Fenning served as Senior Vice President and General Counsel until November 11, 1994; Mr. Fenning currently serves as Vice President and Deputy General Counsel of Mission Energy.
(2) Effective December 31, 1994 Michael L. Noel resigned from his position as Executive Vice President of Mission Land.
None of The Mission Companies' executive officers are related to each other by blood or marriage.
As set forth in Article IV of their respective Bylaws, the officers of The Mission Companies are chosen annually by and serve at the pleasure of the respective Boards of Directors and hold their respective offices until their resignation, removal, other disqualification from service, or until their respective successors are elected.
All of the executive officers have been actively engaged in the business of the respective Mission Companies and/or SCEcorp and Edison for more than five years except for Edward R. Muller, James V.
Iaco, Jr., S. Daniel Melita and Charles W. Johnson. Those officers who have not held their present position for the past five years had the following business experience during that period:
Edward R. Mutter Vice President, Chief Financial Officer, October 1992 to General Counsel and Secretary, August 1993 Whittaker Corporation(1)(12)
Vice President, Chief Administrative March 1988 to Officer, General CounseL and September 1992 Secretary, Whittaker Corporation(2 )(1 2 )
Vice President, Secretary and General October 1991 to CounseL of Biowhittaker, Inc.(12)
August 1993 24
James V. laco, Jr.
President, James V. laco, Jr. & Associates (3)(12)
October 1993 to January 1994 Senior Vice President and Chief Financial Officer October 1992 to of Phoenix Distributors, Inc. (4)(12)
September 1993 Independent Business Consultant(s)
November 1991 to September 1992 Senior Vice President and Chief Financial Officer November 1990 to of Intermark, Inc.(6)( 12)
October 1991 Senior Vice President, Chief Financial Officer September 1981 to and Treasurer of MAXXAM, Inc.(7)(2)
October 1990 Robert Dietch Vice President, Engineering, Planning January 1989 to and Research of Edison January 1992 Thomas R. McDaniel President and Chief Executive Officer --
September 1987 Mission First Financial to February 1992 S. Daniel MeLita Vice President, Mission Energy(8)(12)
September 1992 to October 1993 Vice President, International October 1989 to Operations of EBASCO Constructors August 1992 Inc., EBASCO Overseas Corporation9)(12)
S. Linn Williams Partner of the Law Firm of Jones, Day, October 1993 to Reavis & Pogue(12)
October 1994 Partner of the Law Firm of Gibson, Dunn April 1992 to
& Crutcher(12)
September 1993 Deputy U.S. Trade Representative March 1989 to September 1991 Lawrence W. Yu Senior Vice President of Mission First Financial July 1991 to September 1993 Vice President of Mission First Financial September 1987 to June 1991 Charles W. Johnson President, Glenfed Development Corp.(10)(12)
September 1990 to June 1992 Executive Vice President/Deputy August 1987 to Subsidiary Group Administrator, Glenfed August 1990 Service Corporation(11) (12)
(1) Edward R. Muller served as Chief Financial Officer and General Counsel of Whittaker Corporation.
During the period from 1992 to 1993, the Company was engaged in various aerospace businesses.
(
Edward R. Muller served as Chief Administrative Officer and General Counsel of Whittaker Corporation.
During the period from 1988 to
- 1992, the Company was engaged in various aerospace, chemical and biotechnology businesses which underwent significant restructurings, including a leveraged recapitalization and a tax-free spin off.
As President of James V.
Iaco & Associates, James V.
Iaco, Jr.
provided consultant services specializing in mergers and acquisitions, restructurings,
- finance, crisis management and other management services.
(4) James V.
- Iaco, Jr.
completed the disposition of subsidiaries of Phoenix Distributors, Inc., one of the largest independent industrial gas and welding supply distributors in the United States. Mr. Iaco acted as the Company's chief financial officer, completing the refinancing and restructuring of the remaining operations of the Company.
25
James V.
- Iaco, Jr.
served as an independent business consultant primarily engaged as the chief operating officer of a major developer of time-share resort properties.
As Senior Vice President, Chief Financial Officer, James V. Iaco, Jr.
developed debt reduction and restructuring plans.
James V. Iaco, Jr. served as Senior Vice President, Chief Financial Officer and Treasurer at MAXXAM, Inc., a Fortune 200 company engaged in aluminum production, forest products operations and real estate development.
(8) As Director of International Business Development, S. Daniel Melita planned and implemented international marketing and sales strategies for all business units and was responsible for selecting team partners and establishing joint venture companies.
(9) As Vice President, International Operations of EBASCO Constructors, Inc./EBASCO Overseas Corporation, S. Daniel Melita was responsible for all overseas activities including operations and business development, consulting construction management and lump sum turn key construction.
(10) As President, Charles W. Johnson directed all real estate operations and business combinations which included direct development, joint ventures and syndications.
As Executive Vice President, Charles W. Johnson directed all real estate operations where Glenfed had made a direct equity investment.
This included August Financial Corporation, Glenfed Development Corporation and Glenfed Properties.
(12) This entity is not a parent, subsidiary or other affiliate of SCEcorp.
PART II 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, 1994, ("Annual Report")
under "Quarterly Financial Data" on page 41 and under "Shareholder Information" on page 45, and is incorporated by reference pursuant to General Instruction G(2).
The number of Common Stock shareholders of record was 152,965 on March 20, 1995. 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 and Operating Data: 1990-1994" on page 44, 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 21, 22, 26, and 28 through 30 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 23, 24, 25, 27, and 31 through 40 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.
26
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 20, 1995, 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 headings "Election of Directors of SCEcorp and Edison," and "Stock Ownership of Certain Shareholders" and is incorporated herein by reference pursuant to General Instruction G(3).
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).
On April 20, 1994, Mission Energy made a loan to S. Daniel Melita, Senior Vice President, in the amount of $150,000 in exchange for a note executed by Mr.
Melita and payable to Mission Energy at seven percent (7%)
- interest, annual interest only payments commencing May 1,
- 1994, and continuing to and including May 1, 1997, at which time the entire note, together with accrued interest is due and payable.
In the event Mr.
Melita terminates his employment relationship with Mission Energy prior to the due date of the note, the entire unpaid balance, together with all accrued interest, shall be payable within ninety (90) days of Mr. Melita's departure from Mission Energy.
PART IV Item 14.
Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a)(1)
Financial Statements The following items contained in the 1994 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, 1994, 1993 and 1992 Consolidated Balance Sheets --
December 31, 1994, and 1993 Consolidated Statements of Cash Flows -- Years Ended December 31, 1994, 1993 and 1992 Consolidated Statements of Retained Earnings -- Years Ended December 31, 1994, 1993 and 1992 Notes to Consolidated Financial Statements 27
(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.
Page Report of Independent Public Accountants on Supplemental Schedules 29 Schedule I--Condensed Financial Information of Parent 30 Schedule II--Valuation and Qualifying Accounts for the Years Ended December 31, 1994, 1993 and 1992...
..32 Schedules I through V, inclusive, except those referred to above, are omitted as not required or not applicable.
(3) Exhibits See Exhibit Index on page 35 of this report.
(b)
Reports on Form 8-K None 28
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 1994 Annual Report to Shareholders of SCEcorp, incorporated by reference in this Form 10-K, and have issued our report thereon dated February 3, 1995.
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 LLP Los Angeles, California February 3, 1995 29
SCEcorp SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT CONDENSED BALANCE SHEETS December 31, 1994 1993 (In thousands)
Assets:
Cash and equivalents...........................
88,330 6,004 Other current assets...........................
73,259 143,607 Total current assets........................
161,589 149,611 Investments in subsidiaries 6,104,022 5,934,631 Accumulated deferred income taxes -- net................
1,058 46,768 Other deferred debits 35,000 258 Total assets............................
6,301,669
$6,131,268 Liabilities and Shareholders' Equity:
Accounts payable............................
6,770 S
11,339 Other current liabilities 149,547 162,348 Total current Liabilities......................
156,317 173,687 Other deferred credits.........................
1,936 Common shareholders' equity......................
6,143,416 5,957,581 Total liabilities and shareholders' equity.............
6,301,669
$6,131,268 CONDENSED STATEMENTS OF INCOME For the Years Ended December 31,
- 1994, 1993, and 1992 1994 1993 1992 (In thousands, except per-shareamub Operating revenue and interest income..$...........
S 18,765 S
18,914
$13,974 Operating expenses and income taxes...........
24,305 20,231 14,611 Loss before equity in earnings of subsidiaries.......
(5,540)
(1,317)
(637)
Equity in earnings of subsidiaries.
686,227 640,364 739,357 Net income.......................
680,687 S 639,047
$738,720 Weighted-average shares of common stock outstanding......
447,799 447,754 445,489 Earnings per share 1.52 1.43 1.66 Note: Per-share figures reflect the two-for-one split of SCEcorp common stock effective June 1, 1993.
30
SCEcorp SCHEDULE I--CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)
CONDENSED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1994, 1993, and 1992 1994 1993 1992 (In thousands)
Cash Flows From Operating Activities...........
S 7,326
$(46,143)
$ 1,404 Cash Flows From Financing Activities...........
75,000 41,250 (64,020)
Cash Flows From Investing Activities (456) 3,380 Increase (Decrease) in cash and equivalents.....
.....82,326 (5,349)
(59,236)
Cash and equivalents at beginning of period.....
...6,004 11,353 70,589 Cash and Equivalents at the End of Period.........
S 88,330
$ 6,004
$ 11,353 Cash dividends received from Southern California Edison Company.......................
$548,837
$631,325
$613,816 31
SCEcorp SCHEDULE II --
VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 1994 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:
Nonrecognition of geothermal earnings.....
$ 14,627
$25,467(a)
$ 40,094 Geothermal projects 52,400 52,400 Projects in development stage 18,934 8,548 3,368(b) 24,114 Uncollectible accounts -
Customers..........
16,391 27,240 22,022(c) 21,609 All other..........
41,542 1,428 8,891(c) 34,079 Total...........
$143,894
$ 37,216
$25,467
$ 34,281
$172,296 Group B:
DOE Decontamination and Decommissioning.....
$ 67,128
$ (452)(d) $ 10,191(e) 56,485 Pension and benefits......
131,764 147,037 23,931(f) 127,881(g) 174,851 Insurance, casualty and other............
67,703 67,197 55,173(h) 79,727 Total...........
$266,595
$214,234
$23,479
$193,245
$311,063 (a) Charged to operating revenue.
(b) Accounts written off.
(c)
Accounts written off, net.
(d) Represents new estimate based on actual billings.
(e) Represents amounts paid.
(f) Primarily represents transfers from the accrued.paid absence allowance account for required additions to the comprehensive disability plan accounts.
(g) Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.
(h) Amounts charged to operations that were not covered by insurance.
32
SCEcorp SCHEDULE II --
VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 1993 Additions
.Balance at Charged to Charged to Balance Beginning of Costs and Other at End Description Period Expenses Accoumts Deductions of Period (In thousands)
Group A:
Nonrecognition of geothermal earnings
$ 14,627(a) 14,627 Geothermal projects 52,400 52,400 Projects in development stage 3,921 18,000 2,987(b) 18,934 Uncollectible accounts --
Customers.........
8,970 38,314 481 31,374(c) 16,391 ALI other.........
32,572 12,772 (481) 3,321(c) 41,542 Total..........
S 45,463
$ 121,486
$ 14,627
$ 37,682
$ 143,894 Group B:
Regulatory settlement S 113,380 10,620 S
$124,000(d)
S DOE Decontamination and Decommissioning 53,136 19,156(e) 5,164(f) 67,128 Pension and benefits.....
111,139 48,692 22,064(g) 50,131(h) 131,764 Insurance, casualty and other...........
64,019 51,843 48,159(i) 67,703 Total..........
$ 341,674 S 111,155
$ 41,220
$227,454
$ 266,595 (a) Charged to operating revenue.
(b) Accounts written off.
(c)
Accounts written off, net.
(d) Represents final settlement with the California Public Utilities Commission's Division of Ratepayer Advocates regarding affiliated company power purchases.
(e) Represents new estimate based on actual billings.
(f) Represents amounts paid.
(g) Primarily represents transfers from the accrued paid absence allowance account for required additions to the comprehensive disability plan accounts.
(h) Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.
(i)
Amounts charged to operations that were not covered by insurance.
33
S CE coarp SCHEDULE II --
VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31, 1992 Additions Balance at Charged to Charged to Balance Beginning of Costs and Other at End Description Period Expenses Accoumts Deductions of Period (In thousands)
Group A:
Projects in development stage.
4,667 S
746(a) S 3,921 Uncotlectible accounts --
Customers.........
10,028 23,041 24,099(b) 8,970 ALL other.........
11,934 25,846 5,208(b) 32,572(c)
Total..........
$ 26,629
$ 48,887
$ 30,053
$ 45,463 Group B:
Regulatory settlement S 124,000 S 9,320(d) 19,940(e) $ 113,380 DOE decontamination and decommissioning..
53,136(f) 53,136 Environmental cleanup 40,000 5,000(g) 45,000(h)
Pension and benefits.....
112,007 30,905 20,562(i) 52,335(j) 111,139 Insurance, casualty and other...........
70,513 71,040 77,534(k) 64,019 Total..........
$ 346,520
$ 101,945
$ 88,018
$ 194,809 S 341,674 (a) Accounts written off.
(b) Accounts written off, net.
(c) Includes reserve for net realizable value write-down.
(d) Represents reserve addition for the settlement with the California Public.Utilities Commission's Division of Ratepayer Advocates regarding affiliated company power purchases.
(e) Represents the amortization of the difference between the nominal value and the present value.
(f) Represents the estimated long-term costs to be incurred and recovered through rates over 15 years; reclassified from account 253.
(g) Represents an additional estimated liability established for environmental cleanup costs expected to be incurred and recovered through rates in future years.
(h) Amount reclassified to Account 253, other deferred credits.
(i) Primarily represents transfers from the accrued paid absence allowance account for required additions to the comprehensive disability plan accounts.
(j) Includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.
(k) Amounts charged to operations that were not covered by insurance.
34
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 W. J. Scilacci (W. J. Scilacci, Assistant Treasurer)
Date:
March 27, 1995 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.
Signature Title Date Principal Executive Officer:
John E. Bryson*
Chairman of the Board, March 27, 1995 Chief Executive Officer and Director Principal Financial Officer:
Alan J. Fohrer*
Senior Vice President, Treasurer and Chief March 27, 1995 Financial Officer Controller or Principal Accounting Officer:
Richard K. Bushey*
Vice President and March 27, 1995 Controller Majority of Board of Directors:
Howard P. Allen*
Director March 27, 1995 N. Barker, Jr.*
Director March 27, 1995 Camilla C. Frost*
Director March 27, 1995 Walter B. Gerken*
Director March 27, 1995 Joan C. Hanley*
Director March 27, 1995 Carl F. Huntainger*
Director March 27, 1995 Charles D. Miller*
Director March 27, 1995 J. J. Pinola*
Director March 27, 1995 James M. Rosser*
Director March 27, 1995 Henry T. Segerstrom*
Director March 27, 1995 E. L. Shannon, Jr.*
Director March 27, 1995 Robert H. Smith*
Director March 27, 1995 Daniel M. Tellep*
Director March 27, 1995 James D. Watkins*
Director March 27, 1995 Edward Zapanta*
Director March 27, 1995
- By W. J. Scilacci (W. J. Scilacci, Attorney-in-Fact) 35
0 S
EXHIBIT INDEX Exhibit Number Description 3.1 Restated Articles of Incorporation as amended through April 25, 1988 (Registration No. 33-19541)*.
3.2 Certificate-of Amendment of Restated Articles of Incorporation of SCEcorp (Registration No 33-37381)*
3.3 Bylaws as-adopted by the Board of Directors on February 16, 1995 4.1 Trust Indenture, dated as of October 1, 1923 (Registration No. 2-1369)*
4.2 Supplemental Indenture, dated as of March 1,1927 (Registration No. 2-1369)*
4.3 Second Supplemental Indenture, dated as of April 25, 1935 (Registration No. 2-1472)*
4.4 Third Supplemental Indenture, dated as of June 24, 1935 (Registration No. 2-1602)*
4.5 Fourth Supplemental Indenture, dated as of September 1, 1935 (Registration No. 2-4522)*.
4.6 Fifth Supplemental Indenture, dated as of August 15, 1939 (Registration No. 2-4522)*
4.7 Sixth Supplemental Indenture, dated as of September 1, 1940 (Registration No. 2-4522)*
4.8 Seventh Supplemental Indenture, dated as of January 15, 1948 (Registration No. 2-7369)*...........
4.9 Eighth Supplemental Indenture, dated as of August 15, 1948 (Registration No. 2-7610)*
4.10 Ninth Supplemental Indenture, dated as of February 15, 1951 (Registration No. 2-8781)*
4.11 Tenth Supplemental Indenture, dated as of August 15, 1951 (Registration No. 2-7968)*
4.12 Eleventh Supplemental Indenture, dated as of August 15, 1953 (Registration No. 2-10396)*
4.13 Twelfth Supplemental Indenture, dated as of August 15, 1954 (Registration No. 2-11049)*...........
4.14 Thirteenth Supplemental Indenture, dated as of April 15, 1956 (Registration No. 2-12341)*
4.15 Fourteenth Supplemental Indenture, dated as of February 15, 1957 (Registration No. 2-13030)*
4.16 Fifteenth Supplemental Indenture, dated as of July 1, 1957 (Registration No. 2-13418)*...........
4.17 Sixteenth Supplemental Indenture, dated as of August 15, 1957 (Registration No. 2-13516)*
4.18 Seventeenth Supplemental Indenture, dated as of August 15, 1958 (Registration No. 2-14285)*
4.19 Eighteenth Supplemental Indenture, dated as of January 15, 1960 (Registration No. 2-15906)*
4.20 Nineteenth Supplemental Indenture, dated as of August 15, 1960 (Registration No. 2-16820)*
4.21 Twentieth Supplemental Indenture, dated as of April 1, 1961 (Registration No. 2-17668)*...................
4.22 Twenty-First Supplemental Indenture, dated as of May 1, 1962 (Registration No. 2-20221)*
4.23 Twenty-Second Supplemental Indenture, dated as of October 15, 1962 (Registration No. 2-20791)*
4.24 Twenty-Third Supplemental Indenture, dated as of May 15, 1963 (Registration No. 2-21346)*
36
0 0
EXHIBIT INDEX Exhibit Number Description 4.25 Twenty-Fourth Supplemental Indenture, dated as of February 15, 1964 (Registration No. 2-22056)*.
4.26 Twenty-Fifth Supplemental Indenture, dated as of February 1, 1965 (Registration No. 2-23082)*
4.27 Twenty-Sixth Supplemental Indenture, dated as of May 1, 1966 (Registration No. 2-24835)*
4.28 Twenty-Seventh Supplemental Indenture, dated as of August 15, 1966 (Registration No. 2-25314)*.......
4.29 Twenty-Eighth Supplemental Indenture, dated as of May 1, 1967 (Registration No. 2-26323)*
4.30 Twenty-Ninth Supplemental Indenture, dated as of February 1, 1968 (Registration No. 2-28000)*
4.31 Thirtieth Supplemental Indenture, dated as of January 15, 1969 (Registration No. 2-31044)*
4.32 Thirty-First Supplemental Indenture, dated as of October 1, 1969 (Registration No. 2-34839)*
4.33 Thirty-Second Supplemental Indenture, dated as of December 1, 1970 (Registration No. 2-38713)*
4.34 Thirty-Third Supplemental Indenture, dated as of September 15, 1971 (Registration No. 2-41527)*
4.35 Thirty-Fourth Supplemental Indenture, dated as of August 15, 1972 (Registration No. 2-45046)*.......
4.36 Thirty-Fifth Supplemental Indenture, dated as of February 1, 1974 (Registration No. 2-50039)*
4.37 Thirty-Sixth Supplemental Indenture, dated as of July 1, 1974 (Registration No. 2-59199)*
4.38 Thirty-Seventh Supplemental Indenture, dated as of November 1, 1974 (Registration No. 2-52160)*
4.39 Thirty-Eighth Supplemental Indenture, dated as of March 1, 1975 (Registration No. 2-52776)*
4.40 Thirty-Ninth Supplemental Indenture, dated as of March 15, 1976 (Registration No. 2-55463)*
4.41 Fortieth Supplemental Indenture, dated as of July 1, 1977 (Registration No. 2-59199)*...........
4.42 Forty-First Supplemental Indenture, dated as of November 1, 1978 (Registration No. 2-62609)*
4.43 Forty-Second Supplemental.Indenture, dated as of June 15, 1979 (File No.1-2313)*
4.44 Forty-Third Supplemental Indenture, dated as of September 15, 1979 (File No. 1-2313)*.
4.45 Forty-Fourth Supplemental Indenture, dated as of October 1, 1979 (Registration No. 2-65493)*
4.46 Forty-Fifth Supplemental Indenture, dated as of April 1, 1980 (Registration No. 2-66896)*
4.47 Forty-Sixth Supplemental Indenture, dated as of November 15, 1980 (Registration No. 2-69609)*.......
4.48 Forty-Seventh Supplemental Indenture, dated as of May 15, 1981 (Registration No. 2-71948)*
4.49 Forty-Eighth Supplemental Indenture, dated as of August 1, 1981 (File No. 1-2313)*.
37
S 0
EXHIBIT INDEX Exhibit Number Description 4.50 Forty-Ninth Supplemental Indenture, dated as of December 1, 1981 (Registration No. 2-74339)*
4.51 Fiftieth Supplemental Indentuie, dated as of January 16, 1982 (File No. 1-2313)*
4.52 Fifty-First Supplemental Indenture, dated as of April 15, 1982 (Registration No. 2-76626)*
4.53 Fifty-Second Supplemental Indenture, dated as of November 1, 1982 (Registration No. 2-79672)*
4.54 Fifty-Third Supplemental Indenture, dated as of November 1, 1982 (File No. 1-2313)*................
4.55 Fifty-Fourth Supplemental Indenture, dated as Of January 1, 1983 (File No. 1-2313)*...................
4.56 Fifty-Fifth Supplemental Indenture, dated as of May 1, 1983 (File No. 1-2313)*
I......
4.57 Fifty-Sixth Supplemental Indenture, dated as of December 1, 1984 (Registration No. 2-94512)*
4.58 Fifty-Seventh Supplemental Indenture, dated as of March 15, 1985 (Registration No. 2-96181)*
4.59 Fifty-Eighth Supplemental Indenture, dated as of October 1, 1985 (File No. 1-2313)*..................
4.60 Fifty-Ninth Supplemental Indenture, dated as of October 15, 1985 (File No. 1-2313)*....................
4.61 Sixtieth Supplemental Indenture, dated as of March 1, 1986 (File No. 1-23l3)*
........ I...
4.62 Sixty-First Supplemental Indenture, dated as of March 15, 1986 (File No. 1-2313)*................
4.63 Sixty-Second Supplemental Indenture, dated as of April 15, 1986 (File No. 1-2313)*....................
4.64 Sixty-Third Supplemental Indenture, dated as of April 15, 1986 (File No. 1-2313)*..................
4.65 Sixty-Fourth Supplemental Indenture, dated as of 'July 1, 1986 (File No. 1-2313)*..................
4.66 Sixty-Fifth Supplemental Indenture, dated as of September 1, 1986 (File No. 1-2313)*
4.67 Sixty-Sixth Supplemental Indenture, dated as of September 1, 1986 (File No. 1-2313)*L.............
4.68 Sixty-Seventh Supplemental Indenture, dated as of December 1, 1986 (File No. 1-2313)*'.'.......
4.69 Sixty-Eighth Supplemental Indentur6s dated as of July 1, 1987 (Registration No.-33-19541)*) J!.......
4.70 Sixty-Ninth Supplemental Indenture, dated as of October 15, 1987 (Registration No. 33-19541)*.
4.71 Seventieth Supplemental Indenture, dated as of November 1, 1987 (File No. 1-2313)*.
4.72 Seventy-First Supplemental Indenture, dated as of February 15, 1988 (File No. 1-233)*...........
4.73 Seventy-Second Supplemental Indenture, dated as of April 15, 1988 (File No. 1-2313)*....
2-7.672*.........
4.74 Seventy-Third Supplemental Indenture, dated as of July 1, 1982 (File No. 1-2313)*.
1988 (File No. 1-2313)*..
FityFithSupemntl
- ndnur, atd sofMa 1318
EXHIBIT INDEX Exhibit Number Description 4.75 Seventy-Fourth Supplemental Indenture, dated as of August 15, 1988 (File No. 1-23l3)*............
4.76 Seventy-Fifth Supplemental Indenture, dated as of September 15, 1988 (File No. 1-2313)*...............
4.77 Seventy-Sixth Supplemental indenture, dated as of January 15, 1989 (File No. 1-2313)*....................
4.78 Seventy-Seventh Supplemental Indenture, dated as of May 1, 1990 (File No. 1-23l3)*....................
4.79 Seventy-Eighth Supplemental Indenture, dated as of June 15, 1990 (File No. 1-2313)*.......
4.80 Seventy-Ninth Supplemental Indenture, dated as of August 15, 1990 (File No. 1-23l3)*............
4.81 Eightieth Supplemental Indenture, dated as of December 1, 1990 (File No. 1-2313)*..........
4.82 Eighty-First Supplemental Indenture, dated as of April 1, 1991 (File No. 1-2313)*........................
4.83 Eighty-Second Supplemental Indenture, dated as of may 1, 1991 (File No. 1-2313)*................................
4.84 Eighty-Third Supplemental Indenture, dated as of June 1, 1991 (File No. 1-23l3)*.................
4.85 Eighty-Fourth Supplemental Indenture, dated as of December 1, 1991 (File No. 1-2313)*...............
4.86 Eighty-Fifth Supplemental Indenture, dated as of February 1, 1992 (File.No. 1-23l3)*..............
4.87 Eighty-Sixth Supplemental Indenture, dated as of April 1992 (File No. 1-2313)*..............
4.88 Eighty-Seventh Supplemental Indenture, dated as of July 1, 1992 (File No. 1-23l3)*.............
4.89 Eighty-Eight Supplemental Indenture, dated as of July 15, 1992 (File No. 1-23l3)*............
4.90 Eighty-Ninth Supplemental Indenture, dated as of December 1, 1992 (File No. 1-2313)*..............
4.91 Ninetieth Supplemental Indenture, dated as of January 15, 1993 (File No. 172313)*.......
4.92 Ninety-First Supplemental Indenture, dated as of March 1, 1993 (File N 'o. 1-23l3)*
4.93 Ninety-Second Supplemental Indenture, dated as of June 1, 1993 4.94 Ninety-Third Supplemental Indenture, dated as of June 15, 1993 (File No. 1-2313)*
4.95 Ninety-Fourth Supplemental Indenture, dated as of July 15, 1993 (File No. 1-23i3)*
4.96 Ninety-Fifth Supplemental Indenture, dated as of September 1, 1993 (File No. 1-2313)*...........
4.97 Ninety-Sixth Supplemental Indenture, dated as of gctober 1, 1993 (File No. 1-2313)*.
10.1 Executive Supplemental Benefit Prgram (File No.
1-2313)*
10.2 1981 Deferred Compensation Agreement (File No. 1-2323)3 10.3 1985 Deferred Compensation Agreement for Executives 15, No.(File No.
1-2313)*
10.4 1985 Deferred Compensation Agreement for Directors (File No.
1-2313)*
(Fil 1990 (Fle N.3 1231)*
Eighti987Defet Su menat n
Ind nredaecstfe3 19(File No. 1-2313)*..
Eiht-Frs SppeenalInenur, aedasofApil1
EXHIBIT INDEX Exhibit Number Description 10.6 1987 Deferred Compensation Plan for Directors (File No. 1-2313)*
10.7 1988 Deferred Compensation Plan for Executives (File No. 1-2313)*
10.8 1988 Deferred Compensation Plan for Directors (File No. 1-2313)*
10.9 1989 Deferred Compensation Plan for Executives (File No. 1-9936)*
10.10 1989 Deferred Compensation Plan for Directors (File No. 1-9936)*
10.11 1990 Deferred Compensation Plan for Executives (File No. 1-9936)*
10.12 1990 Deferred Compensation Plan for Directors (File No. 1-9936)*
10.13 Annual Deferred Compensation Plan for Executives (File No. 1-9936)*
10.14 Annual Deferred Compensation Plan for Directors (File No. 1-9936)*
10.15 Executive Retirement Plan (File No. 1-2313)*
10.16 Employment Agreement with Jack K. Horton (File No. 1-2313)*
10.17 Employment Agreement with Howard P. Allen (File No. 1-2313)*
10.18 1991 Executive Incentive Compensation Plan (File No. 1-9936)*
10.19 1992 Executive Incentive Compensation Plan (File No. 1-9936)*
10.20 1993 Executive Incentive Compensation Plan*.
10.21 1994 Executive Incentive Compensation Plan 10.22 Executive Disability and Survivor Benefit Program.
10.23 Retirement Plan for Directors (File No. 1-2313)*
10.24 Long-Term Incentive Plan for Executive Officers (Registration No. 33-19541)*
10.25 Estate and Financial Planning Program for Executive Officers (File No. 1-9936)*.............
10.26 Consulting Agreement with Jack K. Horton (File No. 1-9936)*
10.27 Consulting Agreement with Howard P. Allen (File No. 1-9936)*
10.28 Consulting Agreement with Michael R. Peevey (File No. 1-9936)*
10.29 Employment Agreement with Bryant C. Danner (File No. 1-9936)*
10.30 Employment Agreement with Charles W. Johnson (File No. 1-9936)*
10.31 Letter Agreement with Edward R. Muller
- 11.
Computation of Primary and Fully Diluted Earnings Per Share
- 12.
Computation of Ratios of Earnings to Fixed Charges
- 13.
Selected portions of the Annual Report to Shareholders for year ended December 31, 1994
- 22.
Subsidiaries of the Registrant
- 23.
Consent of Independent Public Accountants - Arthur Andersen LLP.
24.1 Power of Attorney.
24.2 Certified copy of Resolution of Board of Directors Authorizing Signature.
- 27.
Financial Data Schedule...............
- Incorporated by reference pursuant to Rule 12b-32.
40