ML20206H193
| ML20206H193 | |
| Person / Time | |
|---|---|
| Site: | Palo Verde, San Onofre  |
| Issue date: | 05/03/1999 |
| From: | Scherer A SOUTHERN CALIFORNIA EDISON CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| Shared Package | |
| ML20206H197 | List: |
| References | |
| NUDOCS 9905110087 | |
| Download: ML20206H193 (36) | |
Text
kh SOUTHERN CALIfORMA bl EDISON
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A. Edwaed Scherer An LDISON INTLRNAT10%\\L** Company May 3, 1999 U. S. Nuclear Regulatory Commission Attention: Document Control Desk Washington, D. C. 20555
Subject:
Docket Nos. 50-361,50-362,50-528,50-529, and 50-530 Internal Cash Flow for San Onofre Nuclear Generating Station Units 2 and 3, and Palo Verde Nuclear Generating Station Units 1,2, and 3 Gentlemen:
Southern California Edison (SCE), as agent for the owners of San Onofre Nuclear Generating Station Units 2 and 3 and SCE's 15.8% ownership share of Palo Verde Nuclear Generating Station Units 1,2, and 3, submits the following documents in j
accordance with the provisions of 10 CFR 140.21 (e):
4 1999 Internal Cash Flow Projection which is derived from Consolidated Financial e
Statements included in SCE's 1998 Annual Report to Shareholders, as audited and certified by Arthur Anderson, LLP.
SCE's Annual Report to Shareholders for the fiscal year ending December 31,1998.
SCE's Form 10K Annual Report to the Securities and Exchange Commission (Form 10K) for the fiscal year ending December 31,1998.
If you have any questions or need additional information regarding this matter, please feel free to contact me or Jack Rainsberry at (949) 368-7420.
Sincerely, Enclosures cc:
E. W. Merschoff, Regional Administrator, NRC Region IV J. A. Sloan, NRC Senior Resident inspector, San Onofre Units 2 & 3 L. Raghavan NRC Project Manager, San Onofre Units 2 and 3 9905110087 990503 %
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P. O.150x 128 San Clemente, CA 92674-0128 949-368 7501 Fax 949 368 7575 w..
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m SOUTHERN CALIFORNIA EDISON COMPANY 1999 Internal Cash Flow Proinction (Dollars in Thousands) 1998 1999 Actuel Projected Net income After Taxes
$515.122 Dividends Paid
$1.129.812 n; (2)
Retained Earnings
($614,690)
(28 Adjustments:
Depreciation & Decommissioning
$1,545,735
$1,475,870 Not Deferred Taxes & ITC
($94,504)
($275,631)
Allowance for Funds Used During Construction
($19.8721
($19.181)
Total Adjustments
$1,431,359
$1,181,058 Internal Cash Flow
$816,669
'*3 Average Quarterly Cash Flow
$204,167 l
Percentage Ownership in All Nuclear Units San Onofro Nuclear Generating Station Units 2 & 3 o Southern California Edison Company 75.05 %
o San Diego Gas & Electric Company 20.00 %
o City of Anaheim 3.16%
o City of Riverside 1.79 %
Palo Verde Nuclear Generating Station Units 1,2 & 3 15.80 %
Maximum Total Contingent Liability:
Sun 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
'To -:al
$24,740
"' Dividends Paid includes common stock share repurchase
'*3 Company policy prohibits disclosure of financial data which will enable unauthorized persons to forecast earnings or dividends, unless assured confidentiality.
Totomr 1999 CF S/3/99 J
SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 10-K
/X/ Anflual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the fiscal year ended December 31.1998 Commission File Number 1-2313 SOUTHERN CALIFORNIA EDISON COMPANY (Exact name of registrant as specified in its char 1er)
California 95 1240335 (State or other jurisdic';on of (1.R.S. Employer incorporation or organization)
Identification No.)
2244 Walnut Grove Avenue (626)302 1212 Rosemead, California 91770 (Registrant's telephone number, (Address of principal executive offices)
(Zip Code) including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange Title of each class on which reaistered Capital Stock Cumulative Preferred American and Pacific 4.08% Series 4.78% Series 4.24% Series 5.80% Serlee 4.32% Series 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 requirod 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 registrants krowledge, in definitive proxy or information statements incorporated by reference in Part lit of this Form 10-K or any amendment to this Form 10-K. [X)
As of March 19,1999 there were 434,888,104 shares of Common Stock outstanding, all of which are held by the registrant's parent holding company. The aggregate market value of registrant's voting stock held by non-affiliates was approximately $355,326,761 on or about March 19.1999 based upon prices reported by the American Stock Exchange The market values of the various classes of t'oting stock held by non-affiliates, as of March 19,1999, were as follows: CUMULATIVE PREFERRED STOCK $99,626.761; $100 CUMULATIVE PREFERRED STOCK $255,70o,00o.
)
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 31,1998..
.... Parts I, ll and IV (2) Designated portions of tile Joint Proxy Statement relating to registrant's 1999 Annual Meeting of Shareholders....
Part 111
TABLE OF CONTENTS HAR1 PAGE Part i 1.
Business.............
1 1
Competitive Environment......
California Electric Utility Restructuring........................................................
1 Regulation.
4 Rate Matters...
5 Fuel Supply and Purchased Power Costs........................
10 1
Environmentat Matters.......
11 Year 2000 issue.....
14 2.
Properties...........................................................................................
14 Existing Generating Facilities-14 Constructlon Program and Capital Expenditures................................................
16
{
Nuclear Power Matters.......................=................
16 1
3.
- Legal Proceedings.
19 Wind Generators' Litigation '.........................................
19 Geothermal Generators' Litigation.-
19 e.
Electric and Magnetic Fields (EMF) Litigation.
20 San Onofre Personal Injury Litigation.............
21 Mohave Generating Station Environmental Litigation..............
21 4.
Submission of Matters to a Vote of Security Holders...........................
22 Executive Officers of the Registrant 22 Part il t
5.'
Market for Registrant's Common Equity and Related I
Stockholder M atters...........................................................................
25 6.
Selected Financial Data..
25
=.....................
7.
Management's Discussion and Analysis of Results of
- Operations and Financial Condition.............................
25
' 7a.
- Quantitative and Qualitative Disclosures About Market Risk..
25
- 8. '
Financial Ststements and Supplementary Data.....
25 9.
Changes in and Disagreements with Accountants Accounting and Financial Disclosure.'.....................
25 Part til 10.
Directors and Executive Officers of the Registrant =
25 11.
Executive Compensation.........................
26 12.
Security Ownership of Certain Beneficial Owners and Management............
26 13.
Certain Relationships and Related Transactions..............
26 Part IV -
14.
Exhbits, Financial Statement Schedules, and Financial Reports....
26 Reports on Form 8.K......
27 Report of Independent Public Accountants on Supplemental Schedules 28 Supplemental Schedules..............................
29 Sig natures..................._.......
32
. Exhbit i ndex...............................................
33
l PARTI in'this form 10-K, Southem Califomia Edison Company (SCE) uses the words estimates, expects,
- cipates, believes, and other similar expressions that are intended to identify forward-looking b /mation that involves risks and uncertainties. Actual results or outcomes could differ materially as a result of such important factors as further actions by state and federal regulatory bodies that sets rates
. and implement the restructuring of the electric utility industry; the effects of new laws and regulations relating to restructuring and other matters; the effects of increased competition in the electric utility business, including the beginning of direct customer access to retail energy suppliers and the unbundling of revenue cycle services such as metering and billing; changes in prices of electricity and fuel costs; changes in market interest rates; new or increased environmental liabilities; the effects of the Year 2000 on computers; and other unforeseen events.
Item 1. Business SCE was incorporated in 1909 under the laws of the State of California. SCE is a public utility primarily engaged in the business of suppt ing electric energy to a 50,000 square-mile area of Central and
/
Southem Califomia, excluding the City of Los Angeles and certain other cities. This area includes approximately 800 cities and communities and a population of more than 11 million people SCE had 13,177 full-time employees at year-end 1998. During 1998, 31% of SCE's total operating revenue was derived from residential custome,s, 33% from commercial customers,15% from sales to the power exchange (PX), 9% from industrial customers, 6% from public authorities, 5% from agricultural and other customers and 1% from resale customers. SCE comprises the major portion of the assets and revenue of its parent holding company, Edison intemational.
Competitive Environment SCE currently operates in a highly regulated environment in which it has an obligation to deliver electric service to customers in retum for an exclusive franchise within its service territory.. This regulatory environment is changing. In the generation sector, SCE has experienced competition from nonutility power producers; and regulators are restructuring Califomia's electric utility industry to facilitate additional competition. '(See " Business of SCE - Califomia Electric Restructuring" below for a description of these changes.)
California Electric Utility Restructuring Restructuring Decision - The CPUC's December 1995 decision on restructuring Califomia's electric utHity industry started the transition to a new market structure; competition and customer choice began on April 1,1998. Key elements of the CPUC's restructuring decision included: creation of the PX and Independent System Operator (ISO); availability of customer choice for electricity supply and certain billing and metering services; performance-based ratemaking (PBR) for those utility services not subject to competition; voluntary divestiture of at least 50% of utilities' gas-fueled generation; and implementation of the Competition Transition Charge (CTC).
Restructuring Statute - In September 1996, the State of Califomia enacted legislation, Assembly Bill 1890 (AB 1890), to provide a transition to a competitive market structure. The statute substantially adopted the CPUC's restructuring decision by addressing stranded-cost recovery for utilities and providing a certain cost-recovery time period for the transition costs associated with utility-owned generation-related assets. The statute mandated the implementation of the CTC that provides utilities the opportunity to recover costs made uneconomic by electric utility restructuring. Transition costs related to power-purchase contracts are being recovered through the terms of their contracts while most of the remaining transition costs will be recovered through 2001. SCE expects to be able to recover its revenue requirement during the 1998-2001 transition period. The statute also contained provisions for
the recovery (through 2006) of reasonable employee-related transition costs, incurred and projected, for retraining, severance, early retirement, outplacement, and related expenses.
Rate Reduction Notes - In December 1997, after receiving approval from both the CPUC and the Califomia infrastructure and Economic Development Bank, a limited liability company created by SCE issued approximately $2.5 billion of rate reduction notes. Residential and small commercial customers, whose 10% rate reduction began January 1,1998, are repaying the notes over the expected ten-year term through non-bypassable charges based on electricity consumption. There were originally seven classes of Notes. -The first class, in the amount of $246.3 million, matured in December 1998. The remaining notes consist of six classes with maturities ranging from one to nine years, and bear interest ranging from 6.14% to 6.42%.
On November 3,1998, California voters rejected the voter initiative designated as Proposition 9.
Approximately 73% of the total votes cast wore voted against the proposition. Proposition 9 would have prohibited the collection of the non-bypassable charges for the payment of the rate reduction notes and would have severely restructured SCE's recovery of transition costs.
1998 Activities - During 1998, SCE implemented changes to comply with the restructuring elements required by the CPUC and with the restructuring statute. Beginning January 1,1998:
SCE's rates were unbundled into separate charges for energy, transmission, distribution, the CTC, public benefit programs, and nuclear decommissioning. The transmission component is being collected through FERC-approved rates, subject to refund.
SCE's costs associated with hydroelectric plants are being recovered through a performance-based mechanism. The mechanism sets the hydroelectric revenue requirements and establishes a formula for the duration of the electric industry restructuring transition period, or until market valuation of the hydroelectric facilities, whichever occurs first. The mechanism provides that power sales revenue from hydroelectric facilities in excess of the hydroelectric revenue requirement be credited against the costs of transition to a competitive marker environment.
SCE's transition costs are being recovered through a non-bypassable CTC. This charge applies to all customers who were using or began using utility services on or after the CPUC's December 1995 restructuring decision date. SCE has estimated transition costs to be approximately $10.6 billion (1998 net present value) from 1998 through 2030. This estimate is based on incurred costs, forecasts of future costs, and assumed market prices. Changes in the assumed market prices could materially affect these estimates. Potential transition costs are comprised of $6.4 billion from SCE's qualifying facilities contracts, which resulted from prior legislative and regulatory mandates, and $4.2 billion (including the effects of the sale of SCE's gac and oil-fueled generation plants) from costs pertaining to certain generating assets and regulatory commitments consisting of costs incurred (whose recovery has been deferred by the CPUO from providing service to customers. Such commitments include the recovery of income tax benefits previously flowed through to customers, postretirement benefit transition costs, accelerated recovery of San Onofre Units 2 and 3 and the Palo Verde units, and certain other costs. The issue was separated into two phases; Phase 1 addressed the rate-making issues and Phase 2
~
addressed the quantification issues.
Major elements of the CPUC's CTC Phase 1 and Phase 2 decisions were: the establishment of l
a transition cost balancing account and annual transition cost proceedings; the setting of a market rate forecast for 1998 transition costs; the requirement that generation-related regulatory assets be amortized ratably over a 48-month period; the establishment of calculation methodologies and procedures for SCE to collect its transition costs from 1998 through the end of the rate freeze; and the reduction of SCE's authorized rate of return on certain assets eligible for transition cost recovery (primarily fossil-and hydroelectric-generation related assets) beginning July 1997, five months earlier than anticipated. SCE has filed an application for 2
rehearing on tha 1997 rate of return issue. Tha CPUC recently issued a decision agreeing in part with SCE. Although a lower rate of retum was applied to the hydro and fossil assets for the period July 28,1997 through November 21,1997, the retum was set at 7.35% rather than the 7.22% that was adopted in the earlier decision. This increase will result in an additional $425,000 in eamings compared to the original decision.
Residential and small commercial customers who have begun receiving a 10% rate reduction are repaying the rMe reduction notes issued in December 1997 through non-bypassable charges based on electricity consumption. (See " California Electric Utility Restructuring-Rate Reduction Notes" above for additional discussion.)
Effective April 1,1998:
The ISO assumed operational control of the transmission system on March 31,1998, after the ISO and PX began accepting bids and schedules for electricity purchases. The restructuring implementation costs related to the start-up and development of the PX, which are paid by the utilities, will be recovered from all retail customers over the four-year transition period. SCE's share of the charge is $45 million, plus interest and fees. SCE's share of the ISO's start-up and development costs (approximately $16 million per year) will be paid over a ten-year period.
Customers can choose to purchase energy from new retailers called Electric Service Providers (ESPs). As of December 31,1998, approximately 47,000 customers are purchasing their energy from ESPs. All other customers are purchasing energy from SCE, and SCE is in tum purchasing the energy it supplies to them from the PX. Regardless of whom the customers choose to supply their energy, SCE provides transmission and distribution services to all customers within its service territory. All customers of SCE transmission and distribution services also are paying the CTC, regardless of their choice of energy supplier.
Customers have options regarding metering, billing, and related services (referred to as revenue cycle services) provided by Califomia's investor-owned utilities.
ESPs can provide their customers with one consolidated bill for their services and the utility's services, request the utility to provide such a consolidated bill to the customer, or elect to have both the ESP and the utility bill for respective charges. Customers with maximum demand above 20 kWh (primarily industrial and medium and large commercial) can choose SCE or any other supplier to provide their metering service. Beginning in January 1999, all customers may make these choices. SCE may experience a reduction in revenue security as a result of this unbundling.
In September 1998, the CPUC issued a decision requiring SCE to provide credits beginning on January 1,1999, to customers who elect to obtain revenue cycle services from an ESP. The credits are based on the net cost savings to SCE as a result of no longer providing these services. The CPUC, however, has also begun a proceeding to consider whether the RCS credits should be increased to reflect the prices likely to prevail in a competitive market for RCS services. If the CPUC adopts credits based on this premise, SCE has advocated that the resulting difference between payments for the credits and costs actually avoided be recovered from all customers in a competitively neutral manner.
During 1998, SCE sold all of its gas-and oil-fueled generation plants. The total sales price of the 12 plants was $1.2 billion, over $500 million more than the combined book value. Net proceeds of the sales were used to reduce stranded costs, which otherwise were expected to be collected through the CTC mechanism.
Accounting for Generation-Related Assets - if the CPUC's electric industry restructuring plan continues as described above, SCE would be allowe'd to recover its transition costs through non-bypassable charges to its distribution customers (although its investment in certain generation assets would be subject to a lower authorized rate of retum), in 1997, SCE discontinued application of accounting principles for rate-regulated enterprises for its investment in generation facilities based on new 3
accounting guidance. The financial reporting effect of this discontinuanca was to segregate th se assets on the balance sheet; the new guidance did not require SCE to write off any of its generation-related assets, including related regulatory assets. However, the new guidance did not specifically address the application of asset impairment standards to these assets. SCE has retained these assets on its balance sheet j
because AB 1890 and the restructuring plan referred to above make probable their recovery through a non-bypassable CTC to distribution customers. The regulatory assets relate primarily to the recovery of accelerated income tax benefits previously flowed through to customers, purchased power contract termination payments, and unamortized losses on reacquired debt. ' The new accounting guidance also permits the recording of new generation-related regulatory assets during the transition period that are probable of recovery through the CTC mechanism.
During the second quarter of 1998, additional guidance was developed related to the application of asset impairment standards to these assets. Using this guidance resulted in SCE reducing its remaining nuclear plant investment by $2.6 billion (as of June 30,1998) and recording a regulatory asset on its batance sheet for the same amount. For this impairment assessment, the fair value of the investment was calculated by discounting future net cash flows. This reclassification had no effect on SCE's results of operations.
If during the transition period ~ events were to occur that make the recovery of these generation-related regulatory assets no longer probable, SCE would be required to wrte off the remaining balance of such assets (approximately $2.4 billion, after tax, at December 31,1998) as a one-time, non-cash charge against eamings.
if events occur during the restructuring process that result in all or a portion of the transition costs being improbable of recovery, SCE could have additional write-offs associated with these costs if they are not l
recovered through another regulatory mechanism. At this time, SCE cannot predict what other revisions will ultimately be made during the restructuring process in subsequent proceedings or the effect, after the transition period, that competition will have on its results of operations or financial position.
Transmission Owners Tariff and Wholesale Distribution Access Tariff-On March 31,1997, SCE fsled a transmission owners tariff with the FERC, in conjunction with the ISO and PX tariffs, also filed on that date. Together, these tariffs set forth the rate design and terms and conditions for transmission service provided over SCE's facilities over which the ISO will have operational control. The transmission owners tariff also sets forth SCE's proposed transmission access charge. Additionally, on March 31,1997, SCE filed a wholesale distribution access tariff. The FERC accepted the tariffs for filing, subject to refund, effective April 1,1998.
Regulation SCE'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. SCE's wholesale operations are subject to regulation by the FERC. The FERC has the authority to regulate wholesale rates as well as other matters, including transmission service pricing, accounting practices, and licensing of hydroelectric projects.
SCE 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 SCE's power plants within Califomia are subject to the jurisdiction of the Califomia Energy Commission and the CPUC. SCE is subject to the rules and regulations of the Califomia Air Resources Board and local air pollution control districts with respect to the emission of pollutants into the atmosphere; the regulatory requirements of the California State Water Resources Control Board and regional boards with respect to the discharge of pollutants into waters of the state; and the requiremen's of the California Department of Toxic Substances Control with respect to 4
handling and disposal of hazardous materials and wastes. SCE is also subject to regulation by ths EPA, j
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 SCE.
The Califomia Coastal Commission has continuing jurisdiction over the coastal permit for San Onofre Units 2 and 3. Although the units are operating, the permit's mitigation requirements have not yet been fulfilled. Califomia Coastal Commission jurisdiction may continue for several years due to implementation and oversight of permit mitigation conditions, including restoration of wetlands and construction of an artificialreef forkelp.
The Department of Energy (DOE) has regulatory authority over certain aspects of SCE'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.
On December 16, 1997, the CPUC adopted a decision which established new rules goveming the relationship between Califomia's natural gas local distribution companies, electric utilities, and certain of their affiliates. While SCE and its affiliates have been subject to affiliate transaction rules since the establishment of its holding company structure in 1988, these new rules are more detailed and restrictive.
On December 31,1997, SCE filed a preliminary compliance plan which set forth SCE's implementation of the new affiliate transaction rules. This preliminary compliance plan was supplemented by an additional filing made on January 30,1998. In September 1998, the CPUC issued a Resolution accepting certain portions of SCE's compliance plan and rejecting others. SCE filed a revised compliance plan in October 1998 as ordered. No party protested that revised plan.
The new affiliate transaction rules apply to all utility transactions, including electric utilities, with affiliates engaging in the production of products that use electricity or the providing of services that relate to the use of electricity Edison Internationalis not subject to these new affiliate transaction rules and continues to be subject to the prior rules. The new affiliate transaction rules are structured to address CPUC concems regarding market power and cross-subsidization arising out of the new competitive electricity market in California. The new rules are categorized into nondiscrimination standards, disclosure and information standards, and separation standards. The new rules also set forth requirements and restrictions on the utility's offering of certain products and services.
The CPUC.has modified certain of the rules in response to petitions from various parties. SCE is still awaiting CPUC decisions on its compliance plan (which includes SCE's interpretation of the rule goveming affiliate use of the utility's name and logo, on a petition for limited exemptions from that rule, and on SCE's filing relating to utility products and services that produce other operating revenue. The CPUC decision conceming the name and logo rule may affect the disposition of a pending complaint against SCE filed by the CPUC's Office of Ratepayer Advocates (ORA) and The Utility Reform Network with the CPUC, which complaint alleges a violation of that rule by Edison Source in a bulk mailing in 1998.
SCE has not yet been materially affected by the new affiliate transaction rules, and it projects that the rules will not materially affect its results of operation or its financial position in the future.
Rate Matters CPUC Retail Ratemaking The CPUC regulates the charges for services provided by SCE to its retail customers. As discussed above in the section on Califomia Electric Utility Restructuring, the nature in which the CPUC regulates SCE is changing. The CPUC has issued final decisions regarding direct access, transition cost recovery, and rate unbundling in the restructuring of the electric industry. In 1998, these decisions affected cost recovery and rate regulation, and authorized new ratemaking mechanisms which were implemented, 5
replacing the Electric Rev:nus Adjustm:nt Mechanism, Energy Cost Adjustm:nt Clause (ECAC) and base rates mechanism (collectively, the " pre-restructuring ratemaking mechanisms") described in prior annual and quarterly reports filed with the SEC.
Total rates for all customers are frozen at June 10, 1996 levels, although residential and small commercial customers have received a 10% reduction from the June 10,1996 rate levels beginning on January 1,1998. These rate levels will remain in effect for the remainder of the transition period. Under these frozen rates, individual rate components (distribution, transmission, nuclear decommissioning, and public purpose programs) are determined according to CPUC-or FERC-authorized mechanisms, with the generation rate determined residually by subtracting these other components from the total rate.
Beginning for rates effective in 1999, the consolidation of the individual rate component changes and the calculation of the residual generation rate are set forth for CPUC approval as part of the Revenue y
Adjustment Proceeding (RAP). On June 1,1998, SCE filed its first annual RAP Report in compliance with Commission directives to: 1) consolidate authorized rates and revenue requirements associated with various proceedings and mechanisms; 2) verify the residual CTC revenue calculation in the Transition
)
Revenue Account; 3) verify the regulatory account balances which were transferred to the TCBA on January 1, 1998; 4) streamline certain balancing and memorandum accounts; and 5) review the PX charge / credit calculation. SCE anticipates a final 1998 RAP decision in the second quarter of 1999.
The CPUC is considering unbundling SCE's cost of capital based on major utility functions. In May 1998, SCE filed an application on this issue and hearings were completed in October 1998. A CPUC decision is expected in early to mid 1999.
Distribution Rates Distribution cost recovery is made through a distribution PBR mechanism currently authorized through December 2001. Key elements of the distribution PBR include: distribution rates indexed for inflation based on the Censumer Price index less a productivity factor; adjustments for cost changes that are not within SCE's control; a cost of capital trigger mechanism based on changes in a bond index; standards for service reliability and safety; and a net revenue-sharing mechanism that determines how customers and shareholders will share gains and losses from distribution operations. (See "Califomia Electric Utility Restructuring-1998 Activities" above for additional discussion.)
Transmission Rates With the commencement of the ISO and PX on March 31,1998, transmission cost recovery is now under FERC authority. Prior to such commencement, transmission cost recovery was combined with distribution cost recovery through a transmission and distribution PBR mechanism.
Nuclear Decommissioning and Public Purpose Progren Rates Recovery of SCE's nuclear decommissioning costs and legislatively mandated public purpose program funding is made through rates set to recover 100% of these costs. Public purpose programs include cost effective energy efficiency, research, renewable technology development, and low income programs.
Generation Rates l
Effective with the commencement of the ISO and PX operations, generation costs are subject to recovery through the market price and the CTC Revenue available to recover the uneconomic generation costs subject to recovery through the CTC will be determined residually by subtracting the other rate components from the total rates. This residual revenue will first be allocated to recovery of FERC-authorized ISO charges for transmission support and for purchases from the PX, and then to. recovery of l
transition costs. Transition costs associated with QF (Oualifying Facilities) and interutility contracts and the acceleration of sunk cost recovery will be subject to annual reasonableness review by the CPUC.
t i
Transition cost recovery for most utility generation assets will tsrminate on ths carli r of March 31, 2002, or when these costs are fully collected. (See " California Electric Utility Restructuring-1998 Activities" above for additionaldiscussion.)
Annual Transition Cost Proceeding (ATCP) in 1997, the CPUC established the ATCP as the proceeding to determine whether SCE's Transition Cost Balancing Account (TCBA) entries are recorded pursuant to applicable CPUC decisions and AB 1890, and that certain expenses are justified. This proceeding includes matters that for periods prior to July 1, 1998, were considered by the CPUC pursuant to ECAC proceedings. (See " Annual Energy Cost Adjustment Clause Proceedings" below for additional discussion.)
On September 1,- 1998, SCE filed its first ATCP Report with the CPUC and requested that entries made to the TCBA and applicable generation-related memorandum accounts during the record period of January 1,1998 through June 30, 1998 be found to be justified and in compliance with applicable Commission decisions and AB 1890. In addition, SCE requested the Commission to find for the record period that SCE's: 1) purchased power contract administration is justified; 2) coal contract costs are justified; 3) gas fuel procurement and management activities are justified; 4) recorded employee-related costs are justified; 5) proposal for retaining or eliminating generation-related balancing and memorandum accounts is justified; and 6) jurisdictional allocation of transition costs and other generation-related costs should be based upon recorded kWh. SCE anticipates a final 1998 ATCP decision in December,1999.
Recovery of Restructuring implementation Costs The legislature, recognizing that costs accommodating the implementation of direct access, the ISO, and the PX would have to be recovered from within the rates that were frozen at June 1996 levels by other provisions of AB 1890, provided a mechanism to insure that such recovery could occur without impairing the utilities' ability to recover their stranded costs from within frozen rates. This mechanism is contained in Section 376 of the Public Utilities Code, in May 1998, Edison filed an application w;th the CPUC to identify the categories of costs which satisfy the conditions of Section 376, and to establish the reasonableness of those costs incurred in 1997. The CPUC split the application into two phases.
Evidentiary hearings on Phase 1, which addressed the eligibility of cost categories for recovery pursuant M Section 376, concluded in November 1998. A proposed decision on Phase 1 was issued by the administrative law judge (ALJ) on March 11,1999, accompanied by an alternate decision drafted by the assigned commissioner in the proceeding. The attemate decision differs in only minor respects from that I
of the ALJ. Neither of these decisions is binding on any party until acted upon by the full CPUC, which may adopt one or the other of these proposed decisions, modify them, or issue an entirely new decision.
Both of these proposed decisions reject SCE's request for a determination of eligibility under Section 376 for several major categories of costs. These proposed decisions further state that even for the cost categories they approve for Section 376 eligibility, costs incurred in those categories after December 31, 1998 would not be eligible. Instead, these proposed decisions would have SCE recover many of the costs identified in its application from " market revenues," although the decisions fail to identify that market and no specific mechanism or authority to recover such costs from any market has yet been established.
SCE disagrees with much of the conclusions reached in these proposed decisions and will file comments to that effect. A finai decision from the CPUC is curre,tly scheduled for April 22,1999, but may be delayed beyond that date. Under both of the proposed decisions, the reasonableness of 1997 and 1998 expenditures for eligible costs under Section 376 would be addressed in a separate application later this year.
Annual Energy Cost Adjustment Clause Proceedings Ending in 1998, SCE filed ECAC applications each year with the CPUC regarding its fuel and purchased power expenses, seeking the CPUC's determination that SCE's fuel ard purchased power costs, ireluding payments to OFs, were reasonable. These matters are respectively referred to herein as "non-QF matters" and "OF matters."
I 7
QF MATTERS in a decision issued in September 1998, the CPUC found SCE's administration of OF contracts and payments to OF projects (hereinafter referred to as "SCE's OF activities") for the 1992 ECAC to be reasonable.- Review of purchases from three OF projects were deferred because of a pending civil proceeding. The 1992 ECAC was closed, subject to a petition to reopen or modify the decision regarding the deferred OF projects.
The 1993 through 1997 ECAC applications were consolidated for purposes of reviewing OF activities for these years. - ORA issued its review in two different reports in 1998. ORA contested only the reasonableness of SCE's administration of one OF contract known as the Arbutus project. ORA claimed
$3.6 million should be disallowed from recovery. On January 21,1999 an administrative law judge (AU) issued a decision finding SCE's actions with respect to the administration of the Arbutus contract to be reasonable. The AU also confirmed a disallowance of $16.3 million related to the Mojave Cogeneration Company project for the years 1992 through 1997. On March 4,1999, the CPUC issued its decision, upholding the recommendations of the AU. Accordingly, SCE will credit its Electric Deferred Refund Account in the amount of $16.3 million, plus applicable interest, within 30 calendar days after the effective date of the decision. Any recovery SCE receives from the Arbutus bankruptcy proceeding will be credited to SCE's TCBA. This decision closes the 1993,1994,1995,1996, and 1997 Applications, subject to being reopened for the limited puipose of considering issues related to the three projects deferred from the 1992 ECAC proceeding.
ORA issued its report on the 1998 ECAC period on February 19, 1999. ORA did not identify any reasonableness issues associated with SCE's OF activities during the 1998 period.
NON-QF MATTERS 1994 Annual ECAC Record Period SCE filed its non-OF Reasonableness of Operations Report on May 27,1994 for the period April 1,1993 through March 31,1994. This report addresses power purchases and exchanges, and the operation of hydroelectric, coal, gas, and nuclear resources. The non-OF issues were bifurcated, with the gas procurement issues being separated from other non-OF issues. On August 2,1996, the CPUC issued a decision finding that SCE's non-OF, non-gas procurement activities were reasonable.
ORA recommended a $13.3 million disallowance for costs incurred from November 1993 through March 1994 associated with SCE's Canadian gas supply and transportation contracts.
On October 17,1996, the AU granted ORA's motion to consolidate the 1994 and 1995 record periods for the limited purpose of addressing the gas reasonableness issues.
On July 11, 1997 ORA and SCE executed a Settlement Agreement. The basic elements of the settlement include: 1) a $39 million disallowance for Canadian gas costs incurred through December 31, 1996; 2) a disallowance of $257,000 per month, per contract, for each of SCE's four supply contracts for Canadian gas costs beginning after January 1,1997, and continuing until each of the commodity contracts are terminated (one supply agreement was terminated on May 1,1997, and the remaining three supply agreements were terminated on July 1, 1997); 3) a cost sharing mechanism in lieu of reasonableness review, whereby shareholders would absorb at least 20% of the termination or restructuring costs associated with the Canadian supply and transportation contracts and at least 5% of the termination or restructuring costs associated with the El Paso transportation contract which the CPUC has already found reasonable (a portion of these termination or restructuring costs associated with the cost sharing mechanisms would be flowed through to ratepayers through the Energy Deferred Refund Account); and 4) agreement that all other costs incurred under these contracts, including the termination, buy-down and/or buy-out costs are reasonable and should be determined to be reasonable by the CPUC.
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On December 3,1997, the CPUC ksued a dection approving the settlement between SCE cnd ORA.
On March 12,1998, the CPUC approved an advice letter ordering SCE to refund $65 million covering all settlement costs for the 1994,1995,1996, and.1997 ECAC record periods. The settlement has been fully reflected in SCE's financial statements.
1995 Annual ECAC Record Period SCE filed its reasonableness of operations testimony on May 26, 1996 for the period April 1,1994 through March 31,1995 addressing power purchases and exchanges, and the operation of hydroe!9ctric, coal, gas, and nuclear resources for the period April 1,1994, through March 31,1995. In May 1996, ORA issued its reasonableness report on several non-OF reasonableness issues.
The report recommended a $6.6 million disallowance for replacement fuel expenses associated with 64 outage days due to the Palo Verde Unit 2 steam generator tube rupture in 1993, and for nuclear fuel expenses that were later withdrawn by ORA. SCE and ORA executed a stipulation on December 18, 1997,
- "hwmently approved by the CPUC on February 19,1998, resolving the Palo Verde issue by agreeing to a disallowance of $318,540 plus interest which is the replacement fuel expense associated with six outage days.
1997 Annual ECAC Record Period On May 30,1997, SCE filed its annual reasonableness report requesting that the CPUC find reasonable its fuel and purchased-power costs recorded during the period of April 1,1996, through March 31,1997.
ORA's review of the non-OF operations and costs has been consolidated with its review of the non-OF operations and costs for the 1996 ECAC record period. ORA filed its report on August 18,1997. In its report, ORA recommended, among other things: 1) a disallowance of $360,000 associated with an outage at the coal-fired Four Comers Generating Station; 2) a $200,000 adjustment to the costs recorded in SCE's Catastrophic Events Memorandum Account, and 3) a recommendation that SCE's execution of its natural gas transportation contract with Southwest Gas Corporation be found unreasonable for purposes of CTC eligibility. The January 1998 hearings resulted in a CPUC decision issued on October 22,1998, adopting the proposed disallowances. The decision found the execution of the Southwest Gas contract reasonable and therefore, any uneconomic costs associated with the contract will be subject to CTC recovery The remainder of SCE's non-OF costs and expenses were also found reasonable, i
On December 21, 1998, SCE filed a petition for modification of the above decision alleging 'that it erroneously stated that SCE may seek recovery of its Nuclear Unit incentive Procedure (NUIP) rewards in the Revenue Allocation Proceeding. The CPUC found that SCE's calculation of the NUIP reward was reasonable and it was an error for the Commission to order another reasonableness review of these rewards which totaled $15,238,778 plus interest. The February 18,1999, CPUC decision granted SCE's petition to modify the 1998 decision and authorized the booking of the NUIP rewards into the TCBA.
1998 Annual ECAC Record Period On February 19, 1999, ORA issued its Reasonableness Report and made the following recommendations. ORA found that SCE's costs ($239.1 million) recorded in the ISO /PX Implementation Delay Memorandum Account (IPDMA) properly reflected the ISO /PX expenses that accrued during the three month delay in the commencement of ISO /PX operations. ORA also required SCE to include a showing that it undertook all practicable steps to minimize the delay with its request for the recovery of IPDMA costs. ORA found no evidence to show that SCE caused a delay in the ISO /PX implementation.
ORA found that SCE had correctly calculated its NUIP rewards for Palo Verde Units 2 and 3. The NUIP rewards calculated for Unit 2 and 3 were $2.5 million and $1.6 million, respectively. ORA recommended two coal generation related disallowances seeking replacement fuel costs based on December 1997 outages of Mojave Units 1 and 2 in the amount of $2.4 million, and a $1.6 million disallowance related to an outage at Four Comers Unit 5.
ORA also recommended disallowances totaling $5.6 million plus interest, to correct for audit errors. SCE is investigating the facts behind these recommended 9
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disallowances recommendations and expects to fils rebuttal testimony on April 26,1999. Hrarings ara J
scheduled in May 1999.
Palo Verde in January 1997, the CPUC authorized a further acceleration of the recovery of SCE's remaining investment of $1.2 billion in Palo Verde Units 1,2, and 3. The accelerated recovery will continue through December 2001, eaming a 7.35% fixed rate of retum. The future operating costs, including nuclear fuel and nuclear fuel financing costs, and incremental capital expenditures, are subject to balancing account I
treatment through 2001. Beginning January 1,1998, the balancing account became part of the CTC l
mechanism. The existing nuclear unit incentive procedure will continue only for purposes of calculating a reward for performance of any unit above an 80% capacity factor for a fuel cycle. Beginning in 2002, SCE will be required to share the net benefits received from the operation of Palo Verde equally with ratepayers.
San Onofre Nuclear Generating Station Units 2 and 3 in April 1996, the CPUC authorized a further acceleration of the recovery of SCE's remaining investment of $2.6 billion in San Onofre Units 2 and 3. The accelerated recovery will continue through December 2001, eaming a 7.35% fixed rate of retum. San Onofre's operating costs, including nuclear fuel, nuclear fuel financing costs, and incremental capital expenditures, are recovered through an incentive pricing plan which allows SCE to receive about 4.0c per kWh through December 31, 2003. Beginning January 1, 1998, the accelerated plant recovery and incremental cost incentive pricing became part of the CTC mechanism. Beginning in 2004, SCE will be required to share the net benefits received from operation of San Onofre Units 2 and 3 equally with ratepayers.
New Accounting Rules A recently issued accounting rule requires that costs related to start-up activities be expensed as incurred, effective January 1,1999. SCE does not expect this new accounting rule to materially affect its results of operations or its financial position.
In June 1998, a new accounting standard for derivative instruments and hedging activities was issued.
The new standard, which will be effective January 1,2000, requires all derivatives to be recognized on the balance sheet at fair value. Gains or losses from changes in fair value would be recognized in samings in the period of change unless the derivative is designated as a hedging instrument. Gains or losses from hedges of a forecasted transnction or foreign currency exposure would be reflected in other comprehensive income. Gains or losses from hedges of a recognized asset or liability, or a firm commitment would be reflected in eamings for the ineffective portion of the hedge. SCE anticipates that most of its derivatives under the new standard would qualify for hedge accounting. SCE expects to recover in rates any market price changes from its derivatives that could potentially affect earnings.
Accordingly, implementation of this new standard is not expected to affect earnings.
Fuel Supply and Purchased Power Costs Since April 1,1998, SCE has been required to purchase all power for distribution to retail customers from the PX. In 1998, fuel and purchased-power costs, excluding that purchased from the PX, were approximately $3.1 billion, which was a 20% decrease from the costs in 1997.
SCE's sources of energy during 1998 were as follows: 54% purchased power; 4% naturai gas; 22%
nuclear; 13% coal; and 7% hydro.
Average fuel costs, expressed in e per kWh, for the year ended December 31,1998, were: oil, 6.03c; natural gas, 3.06c; nuclear, 0.48c; and coal,1.23c.
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Natural Gas Supply As a result of the sale of all of its gas-fired generating stations, SCE has terminated four long-term natural gas supply and three long-term gas transportation contracts which had been used to import gas from Canada. In addition, SCE has exercised an option under its 15-year gas transportation commitment with El Paso Natural Gas Company to reduce its capacity obligation from 200 million to 130 million cubic feet per day.
Nuclear Fuel Supply SCE has contractual arrangements covering 100% of the projected nuclear fuel requirements for San Onofre through the years indicated below:
Uraniu m concentrat es(*).................................................................
2003 Conversion..............................................
2003 Enrichment..............................
2003 Fabrication.........
2005
(*) Assumes the San Onofre participants meet their supply obligations in a timely manner.
Assuming normal operation and full utilization of existing on-site stcrage capacity, San Onofre Units 2 and 3 will maintain full-core offload reserve through 2005. The Nuclear Waste Policy Act of 1982 requires that the DOE provide for the disposal of utility spent nuclear fuel beginning January 31,1998. The DOE has defaulted on its obligation to begin acceptance of spent nuclear fuel from the commercial nuclear industry by that date. Additional spent fuel storage either on-site or at another location will be required to permit continued operations beyond 2005.
Participants at Palo Verde have contractual agreements for uranium concentrates to meet projected requirements through 2000. Independent of arrangements made by other participants, SCE will furnish its share of uranium concentrates requirement through at least 1999 from existing contracts. Contracts covering 100% requirements are in place for conversion through 1998, enrichment through 2002, and fabrication through 2016.
Assuming normal operation and regulatory approval for more condensed on-site spent fuel storage, Palo Verde Units 1, 2, and 3 will maintain full-core offload reserve until the spring of 2002, fall of 2002, and spring of 2003, respectively. Arizona Public Service, operating agent for Palo Verda, has commenced construction of an interim fuel storaga facility that it projects will be completed in 2002.
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 nuclee* control continue to result in the imposition of numerous restrictions on SCE's operation of existing facilities, on the timing, cost, location, design, construction, and operation by SCE of new facilities, 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 SCE's existing facilities and operating procedures. SCE is unable to predict the extent to which additional regulations may affect its operations and capital expenditure requirements.
The Clean Air Act (CAA) 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 CAA as amended in 1990, and as implemented within the South Coast Air Quality Management District (SCAQMD) and other Califomia districts, required SCE to reduce emissions of oxides of nitrogen from its generating stations. During 1998, SCE sold all of its oil-and gas fueled generating stations 11
L within the Mohave Desert Air Quality Manag;m:nt District, Ventura County Air Pollution Control District, and in the Santa Barbara County Air Pollution Control District. SCE has sold all but one of its oil-and gas-fired generating stations within the SCAQMD. The remaining plant, the Pebbly Beach Generating Station, supplies power to Santa Catalina Island. After the sale of its oil-and gas-fueled generating stations, SCE commenced operation of the facilities under operation and maintenance contracts with the individual owners except for two plants that ceased operation during 1998. SCE will continue to operate or, where applicable, commence operating those divested facilities as active generating stations for the required two-year period specified by Califomia's restructuring statute implementing deregulation of electric utilities in the state. SCE's operation of the stations under these operation and maintenance contracts is at the direction and expense of the new owners. SCE is responsible for maintaining the environmental permits for the plants. The new owners, not SCE, are responsible for the purchase and installation of emissions control equipment, and for obtaining trading credits required for the plants under the Regional Clean Air incentives Market within the SCAQMD.
The CAA does not require any other significant ernissions control expenditures that are identifiable at this time. The Environmental Protection Agency (EPA) plans to issue its final rulemaking regarding regional haze regulations in mid-1999. The EPA and SCE are also expected to conclude a cooperative tracer study of sulfur dioxide emissions from the Mohave Generating Station (Mohave) in early 1999. The study is currently evaluating potential impact from Mohave emissions on haze within the Grand Canyon National Park. On February 19,1998, the Sierra Club and the Grand Canyon Trust filed suit in the U.S.
District Court of Nevada against SCE and the other co-owners of Mohave alleging violations, over the last five years of the CAA, the Nevada State Implementation Plan, and applicable air quality permits relating to opacity and sulfur dioxide emission limits. (See, " Southern California Edison Company-Mohave Generating Station Environmental Litigation" below for additional discussion.) SCE has asked Business for Social Responsibility and Environment Now, two well respected organizations, to convene a collaborative of interested stakeholders to discuss the best way to resolve this issue. In anticipation of this dialogue, SCE has proposed to install a dry scrubber, baghouse, and low-NOx burners at Mohave by 2008. This proposal, however, is subject to discussion and modification as part of the collaborative. The acid rain provisions of the amended CAA also put an annual limit on sulfur dioxide emissions allowed from power plants. SCE has received more sulfur dioxide allowances than required for its projected operations. Until the collaborative process is completed and a firm requirement adopted, SCE expects to meet all of the present regulations through improved operations at Mohave.
The CAA also requires the EPA to carry out a three-year study of risk to public health from the emissions of tov.ic air contaminants from electric utility steam generating plants, and to regulate such emissions if required. The study's final report to Congress concluded that mercury from coal-fired utilities is the l
hazardous air pollutant of greatest potential concem and merits additional research and monitoring to l
better understand the risks of mercury exposure. Other pollutants that may potentially need further study
- are dioxins and arsenic from coal-fired plants, and nickel from oil-fired plants. The EPA concluded that the impacts from emissions from gas-fired utilities are negligible and that there is no need for further evaluation of the risks of hazardous air pollutants.
Regulations under the Clean Water Act require permits for the discharge of certain pollutants into U.S waters. 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 more stringent limitations. SCE incurs additional expenses and capital expenditures in order to comply with guidelines and standards applicable to steam electric power plants. SCE 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 Califomia to cause cancer or reproductive harm and the discharge of such listed l
chemicals into potential sources of drinking water. Additional chemicals are continuously being put on the j
state's list, requiring constant monitoring.
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The Rescurce Conservation and Recovery Act (RCRA) providss the statutory authority for the EPA to implement a regulatory program for the safe treatment, recycling, storage, and disposal of solid and hazardous wastes. An unresolved issue remains regarding the degree to which coal wastes should be regulated under the RCRA. Increased regulation may result in increased expenses relating to the operation of Mohave.
The Toxic Substances 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. Current costs for disposal of this substance are immaterial.
SCE records its environmental liabilities when site assessments and/or remedial actions are probable and a range of reasonably likely cleanup costs can be estimated. SCE reviews its sites and measures the liability quarterly, by assessing a range of reasonably likely costs for each identified site using currently available information, including existing technology, presently enacted laws and regulations, experience gained at similar sites, and the probable level of involvement and financial condition of other potentially responsible parties. These estimates include costs for site investigations, remediation, operations and maintenance, monitoring, and site closure. Unless there is a probable amount, SCE records the lower end of this reasonably likely range of costs (classified as other long-term liabilities at discounted amounts).
SCE's recorded estimated minimum liability to remediate its 49 identified sites is $171 million. The ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process, such as: the extent and nature of contamination; the scarcity of reliable data for identified sites; the varying costs of alternative cleanup methods; developments resulting from investigatory studies; the possibility of identifying additional sites; and the time periods over which site remediation is expected to occur. SCE believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $247 million. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes. SCE has sold all of its gas-and oil-fueled generation plants and has retained some liability associated with the divested properties.
The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites, representing $88 million of its recorded liability, through an incentivn mechanism (SCE may ask to include additional sites). Under this mechanism, SCE will recover 90% of cleanup costs through customer rates (shareholders fund the remaining 10%), with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. Costs incurred at SCE's remaining sites are expected to be recovered through customer rates. SCE has recorded a regulatory asset of $141 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates.
SCE's identified sites include several sites for which there is a lack of currently available information, including the nature and magnitude of contamination, and the extent, if any, that SCE may be held responsible for contributing to any costs incurred for remediating these sites. Thus, no reasonable estimate of cleanup costs can be made for these sites.
SCE expects to clean up its identified sites over a period of up to 30 years. Remediation costs in each of the next several years are expected to range from $4 million to $10 million. Recorded costs for 1998 were $7 million.
Based on currently available information, SCE believes that it is unlikely 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, SCE believes that costs ultimately recorded will not materially affect its results of operations or its financial position. There is 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.
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SCE's projeted environmental capital expenditures are $900 million for the 1999-2003 period. These expenditures are mainly for aesthetic treatment, including undergrounding certain transmission and distribution lines.
Year 2000 issue Many of SCE's existing computer systems identify a date by using only six digits instead of eight. If not appropriately addressed, these programs could fail or create erroneous results when attempting to process information containing dates after December 31, 1999. This situation has been referred to generally as the Year 2000 Issue.
SCE has a comprehensive program in place to address potential Year 2000 impacts. SCE divides Year 2000 activities into five phases: inventory, impact assessment, remediation, testing, and implementation.
Edison international provides overall coordination of this effort, working with SCE and their business units.
Remediation of SCE's key financial systems for the Year 2000 issue was completed in 1997. SCE's informational and operational systems have been assessed, and detailed plans have been developed to address modifications required to be completed, tested, and operational by December 31, %99. Year 2000 readiness preparations for SCE's mainframe financial systems were completed in the t
- quarter of 1997, and preparations for SCE's material management system were completed in the sewd quarter of 1998. SCE's customer information and billing system is in the process of being replaced with a system designed to be Year 2000-ready and final conversion activities are expected to be completed by the first quarter of 1999. SCE's distributed computing assets include operations and business information systems.
SCE's critical operations information systems include outage management, power management, and plant monitoring and access retrieval systems. SCE's business information systems include a data acquisition system for billing, the computer call center support system, credit support, and maintenance management. SCE's current estimate of the costs to complete these modifications, including the cost of new hardware and software application modification, is $72 million, about 40% of which is expected to be capital costs. SCE's Year 2000 costs expended through December 31,1998, were $35 million. SCE expects current rate levels for providing electric service to be sufficient to provide funding for utility-related modifications. SCE expects its Year 2000 date conversion project to be completed on a timely basis, with no material adverse impact to its results of operations or financial position.
Another aspect of SCE's program involves developing contingency plans. Final drafts of such plans are expected to be completed by March 1999, with management approval thereof scheduled for May 1,1999.
These plans will continue to be revised and enhanced as the year 2000 approaches.
SCE's objectives for the Year 2000 readiness of critical systems was to be 75% complete by year-end 1998, and to be 100% complete by July 1999. SCE was 80% complete at year-end 1998 and is on track to meet its July 1999 goal.
SCE's Year 2000 date conversion project includes an assessment of critical interfaces with the computer systems of others, and it does not expect a material adverse effect on its operating and business functions from the Year 2000 issue. (See item 7, Management's Discussion and Analysis of Results of Operations and Financial Condition
" Year 2000 issue" below for additional discussion.)
ltem 2. Properties Existing Generating Facilities SCE owns and operates one diesel-fueled generating plant located on Santa Catalina island, 36 hydroelectric plants, and an undivided 75.05% interest (1,614 MW net) in Units 2 and 3 at San Onofre.
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These plants ara located in Central and Southem California. By the end of 1998, SCE had sold all 12 of its gas-fueled generating plants.
SCE also owns a 15.8% share of the Palo Verde (579 MW net) Nuclear Generating Station which is located near Phoenix, Arizona. SCE owns a 48% undivided interest (754 MW) in Units 4 and 5 at the Four Corners Generating Station, which is a coal-fueled steam electric generating plant located in New Mexico. Palo Verde and Four Corners are operated by other utilities. SCE operates and owns a 56%
undivided interest (885 MW) in the Mohave Generating Station, which consists of two coal-fueled steam electric generating units in Clark County, Nevada. At year-end 1998, the existing SCE-owned generating capacity (summer effective rating) was divided approximately as follows: 43.9% nuclear, 32.8% coal, 23.1% hydroelectric, and 0.2% oil.
San Onofre, Four Comers, certain of SCE's substations and portions of its transmission, distribution and communication systems are located on lands of the U. S. 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 SCE, 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 govemments.
The 36 hydroelectric plants, some with related reservoirs, currently having an effective operating capacity of 1,156 MW, and are, with five exceptions, located in whole or in part on lands of the U.S. pursuant to, 30 to 53 year governmental licenses that expire at various timos between 1998 and 2026. Such licenses impose numerous restrictions and obligations on SCE, including the right of the United States to acquire 4
projects 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 SCE's and then only upon payment of specified compensation to SCE. Any new licenses issued to SCE are expected to be issued under terms and conditions less favorable than those of the expired licenses.
SCE's applications for the relicensing 'of certain hydroelectric projects with an aggregate effective operating capacity of 115.57 MW are pending. The SCE hydroelectric projects that aie undergoing relicensing and whose long-term licenses have expired, have been issued annual licenses, which will be renewed until the new licenses are issued.
In 1998, SCE's peak demand was 19,935 MW, set on August 31, 1998. Substantially all of SCE's properties are subject to the lien of a trust indenture securing First and Refunding Mortgage Bonds (Trust Indenture), of which approximately $2.5 billion in principal amount was outstanding on December 31, 1998. Such lien and SCE'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 SCE's title to its properties are subject to certain other liens, prior rights and other encumbrances, none of which, with minor or unsubstantial exceptions, affect SCE's right to use such properties in its business, unless the matters with respect to SCE's interest in Four Corners and the related easement and lease referred to below may be so considered.
SCE's rights in the Four Comers Project, which is located on land of The Navajo Nation of Indians under an easement from the U. S. 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 SCE to resort to legal process to enforce its rights against The Navajo Nation without Congressional consent, possible impairment or termination l
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 SCE's interest in the easement, lease, and improvements on the Four Corners Project.
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Constructlan Program cnd Capitil Expendituras Cash required by SCE for its capital expenditures totaled $861 million in 1998, and $685 million in 1997 and $616 million in 1996. Construction expenditures for the 1999-2003 period are forecasted at $3.9 billion.
In addition to cash required for construction expenditures for the next five years as discussed above, $2.4 billion is needed to meet requirements for long-term debt maturities and sinking fund redemption requirements.
SCE's estimates of cash available for operations for the five years through 2003 assume, among other things, the receipt of adequate and timely rate relief and the realization of its assumptions regarding cost increases, including the cost of capital. SCE'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 SCE's Articles of Incorporation and Trust Indenture.
Nuclear Power Matters SCE's nuclear facilities have been reliable sources of inexpensive, non-polluting power for SCE's customers for more than a decade. Throughout the operating life of these facilities, SCE's customers have supported the revenue requirements of SCE's capital investment in these facilities and for their incremental costs through tra 1tional cost-of-service ratemaking.
In 1996, the CPUC adopt' CE's San Onofre Unit 2 and 3 proposal under which SCE would have recovered its remaining inyt..nent in these San Onofre Units at a reduced rate of retum of 7.35%, but on an accelerated basis iring the eight-year period from the effective date in 1996 through December 31, 2003. AB iud 0, however, requires the recovery of the San Onofre investment to be completed by December 31,2001. In addition, the traditional cost-of-service ratemaking for San Onofre Units 2 and 3 was superseded by an incentive pricing plan in which SCE's customers pay a preset price for each kWh of energy generated at San Onofre during the eight-year period. AB 1890 allows for the continuation of the incentive pricing plan through December 31,2003. SCE was compensated for the incremental costs required for the continued operation of San Onofre Units 2 and 3 with revenue earned through the incentive pricing plan. SCE also retained the ability to request recovery of the cost of fuel consumed for generation of replacement energy for periods in which San Onofre will not generate power through ECAC filings and, beginning in 1998, as part of ATCP. AB 1890 also allows SCE to continue to collect funds for decommissioning expenses through traditional ratemaking treatment.
On July 16,1997, the CPUC approved SCE's request to transfer the recorded net investment in San Onofre Units 2 and 3 step-up transformers to San Onofre Units 2 and 3 sunk costs for recovery by December 31,2001, at a reduced rate of retum of 7.35%.
On August 21,1997, the CPUC approved San Diego Gas & Electric's (SDG&E) and SCE's Joint Petition to Modify, requesting continued recovery of certain corporate administrative and general costs allocable to San Onofre Units 2 and 3, at rates of 0.28c and 0.21e per kWh, respectively, for the period January 1, 1998, through December 31,2003.
In 1996, SCE filed its Palo Verde Proposal Application requesting adoption of a new rate mechanism for Palo Verde consistent with that of San Onofre Units 2 and 3. On November 15,1996, SCE, ORA, and TURN entered into a settlement agreement, which was approved by the CPUC on December 20,1996, regarding SCE's Palo Verde Proposal Application which now allows SCE to recover its remaining investment in the Palo Verde units by December 31, 2001, at a reduced rate of retum of 7.35%
consistent with AB 1890. The settling parties agreed that SCE would recover its share of Palo Verde 16
increm:ntal operating costs, except if those costs exceed 95% of the levels forecast by SCE in its application by more than 30% in any given year in which case, SCE must demonstrate that the aggregate amount of the costs exceeding the forecast in that year are reasonable. If the annual Palo Verde site Gross Capacity Factor (GCF) is less than 55% in a calendar year, SCE will bear the burden of proof to demonstrate that the site's operations causing the GCF to fall below 55% were reasonable in that year. If operations are determined to be unreasonable by the CPUC, SCE's replacement power purchases associated with that period of Palo Verde operations below 55% GCF may be disallowed.
Beginning in 2002, the benefits of future operation of Palo Verde Units 1,2, and 3 will be shared equally between shareholders and customers. Likewise, beginning in 2004, the benefits of future operation of San Onofre Units 2 and 3 will be shared equally between shareholders and customers.
San Onofre Nuclear Generating Station in 1992, the CPUC approved a settlement agreement between SCE and the ORA to discontinue operation of Unit 1 at the end of its then-current fuel cycle. In November 1992, SCE discontinued operation of Unit 1. As part of the agreement, SCE recovered its remaining investment over a four-year period ending August 1996. On December 21,1998, SCE filed an application with the CPUC requesting authorization to access its Nuclear Decommissioning Trust Funds for Unit 1 for the purpose of commencing decommissioning of Unit 1 in 2000.
The Units 2 and 3 steam generators have performed relatively well through the first 15 years of operation, with low rates of ongoing steam generator tube degradation. During the Unit 2 scheduled refueling and inspection outage, which was completed in 1997, an increased rate of degradation was identified, which resulted in the removal of more tubes from service than had been expected. The present design analysis, which is being reviewed for a potential increase, allows for the removal of up to 10% of the steam generator tubes before the unit's capacity must be re-evaluated. As a resuit of the increased degradation, a mid-cycle outage was conducted in early 1998 for Unit 2. Continued degradation was found during this inspection. A favorable (decreasing) trend in degradation was observed during inspection in the scheduled refueling outage in January 1999. The results of the January 1999 inspection are being analyzed to determine if there is a need for a mid-cycle inspection outage in early 2000. With the results from the January 1999 outage,7.5% of the tubes have now been remcved from service. In September 1998, San Onofre Unit 2 experienced a small amount of leakage from a steam generator tube plug, which required an 11-day outage to repair.
During Unit 3's refueling outage, which was completed in July 1997, inspections of structural supports for steam generator tubes identified several areas where the thickness of the supports had been reduced, apparently by erosion during normal plant operation. A follow-up mid-cycle inspection indicated that the erosion had been stabilized. Additional monitoring inspections are planned during the next scheduled refueling outage in 1999. To date,5% of Unit 3's tubes have been removed from service.
During Unit 2's February 1998 mid-cycle outage, similar tube supports showed no significant levels of such erosion.
Palo Verde Nuclear Generating Station Based on latest available data, APS estimates that the Unit 1 and Unit 3 steam generators should operate for the 40 year licensed operating life of those units, although APS continues to monitor the situation. APS has disclosed that it believes that it will be economically desirable to replace the Unit 2 steam generators, which have been most affected by tube cracking, in four to nine years. APS has indicated to the participants that it believes that replacement of the Unit 2 steam generators would cost between $100 million and $150 million. SCE estimates that this cost could be higher, such that its share of this cost would be between $16 million and $30 million plus replacement power costs. Unanimous approval of the Palo Verde participants is required for capital improvements, including steam generator replacement, in December 1997, the Palo Verde participants unanimously agreed to purchase two spare 17
steam generitors at a cost of approximately $82 million; however, SCE has not yet decided whether it supports replacement of the Unit 2 steam generators.
During 1998, Palo Verde Nuclear Generating Station generated 30 billion kWh of electricity. It was the iirst time an American power plant of any kind crossed the 30-billion-kilowatt-hour threshold in a single year. Palo Verde broke its own record of 29.5 billion kWh that it set in 1997 and was the nation's top power producer for the fourth consecutive year. The year-end station capacity factor was 92.5%. Units 1 and 3 were each refueled in 36-day outages - a site record. Unit 2 operated on-line the entire year and at year's end had operated continuously for 430 days.
Nuclear Facility Decommissioning With the exception of San Onofre Unit 1, SCE plans to decommission its nuclear generating facilities at the end of each facility's operating license by a prompt removal method authorized by the NRC. On December 21, 1998, SCE filed an application with the CPUC requesting the authority to access its decommissioning trust funds for San Onofre Unit 1 for the purpose of decommissioning commencing in 2000. Decommissioning is estimated to cost $1.9 billion in current-year dollars based on site-specific studies performed in 1998 for San Onofre and Palo Verde. This estimate considers the total cost of decommissioning and dismantling the plant, including labor, material, burial, and other costs. The site specific studies are updated approximately every three years. Changes in the estimated costs, timing of decommissioning, or the assumptions underlying these estimates could cause material revisions to the estimated total cost to decommission in the near term. Decommissioning is scheduled to begin in 2000 at San Onofre Unit 1. SCE expects decommissioning San Onofre Units 2 and 3 and Palo Verde to occur after its generating licenses expire in 2013 and 2024 respectively.
Decommissioning expense was $164 million in 1998 and $154 million in 1997. The accumulated provision for decommissioning was $1.2 billion at December 31,1998, and $1.1 billion at December 31, 1997. The estimated costs to decommission San Onofre Unit 1 ($368 million in 1998 dollars) are recorded as a liability.
Decommissioning funds collected in rates are placed in independent trusts which, together with accumulated earnings, will be utilized solely for decommissioning.
Nuclear insurance Federal law limits public liability claims from a nuclear incident to $9.8 billion. SCE and other owners of San Onofre and Palo Verde have purchased the maximum private primary insurance available ($200 million). The balance is covered by the industry's retrospective rating plan that uses deferred premium charges to every reactor licensee if a nuclear incident at any licensed reactor in the U.S. results in claims and/or costs which exceed the primary insurance at that plant site. Federal regulations require this secondary level of financial protection. The NRC exempted San Onofre Unit 1 from this secondary level, effective June 1994. The maximum deferred premium for each nuclear incident is $88 million per reactor, j
but not more than $10 million per reactor may be charged in any one year for each incident. Based on its ownership interests, SCE could be required to pay a maximum of $175 million per nuclear incident. SCE, however, would have to pay no more than $20 million per incident in any one year. Such premium amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to penodic adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims. including a possible additional assessment on all licensed reactor operators.
i Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary
$500 million has also been purchased in amounts greater than federal requirements. Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage.
These policies are issued primarily by mutual insurance companies owned by utilities with nuclear 18 i
r-facilities.
If losses at any nuclear facility covered by these arrangements wirs to exceed the accumulated funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to $22 million per year. Insurance premiums are charged to operating expense.
j Item 3. Legal Proceedings Wind Generators' Litigation SCE was named as a defendant in a series of s'.ght lawsuits brought by independent power producers of wind generation. Seven of the lawsuits were fileciin Los Angeles County Superior Court and one was filed in Kem County Superior Court. The lawsuits alleged that SCE incorrectly interpreted contracts with the plaintiffs by limiting fixed energy payments to a single ten-year period rather than beginning a new ten-year period of fixed energy payments for each stage of development. In its responses to the complaints, SCE denied the plaintiffs' allegations. In each of the lawsuits, the plaintiffs sought declaratory relief regarding the proper interpretation of the contracts. Plaintiffs alleged a combined total of approximately $189 million in damages, which included consequential damages claimed in seven of the eight lawsuits. A ninth lawsuit was subsequently filed in Los Angeles County raising claims similar to those alleged in the first eight. SCE responded to the complaint in the new lawsuit by denying its material allegations.
After receiving a favorable decision in the liability phase of the lead case, SCE agreed to settle with the plaintiffs in seven of the lawsuits on terms whereby SCE waived its rights to recover costs against such
]
plaintiffs in exchange for their agreement that there is only one fixed price period under each of their e
power purchase contracts with SCE and a mutual dismissal with prejudice of claims. SCE also entered into a settlement agreement with the plaintiff in another of the lawsuits which resolved the issue of L
multiple fixed price periods on the same terms and which also resolved a related issue unique to that j
plaintiff in exchange for a nominal payment by SCE. This settlement was approved by the bankruptcy I
court in proceedings involving the plaintiff. On January 28,1999, SCE finalized a settlement with the l
remaining plaintiffs on terms effectively the same as those in the initial group of settlements except that the' settlement agreement also resolved, on terms favorable to SCE, certain claims which SCE had asserted in the lead case by way of cross-complaint, 1
Geothermal Generators' Litigation On June 9,1997, SCE filed a complaint in Los Angeles County Superior Court against an independent l
power producer of geothermal generation and six of its affiliated entities (Coso parties). SCE alleges that I
in order to avoid power production plant shutdowns caused by excessive noncondensable gas in the geothermal field brine, the Coso parties routinely vented highly toxic' hydrogen sulfide gas from unmonitored release points beginning in 1990 and continuing through at least 1994, in violation of i
applicable federal, state, and local environmental law. According to SCE, these violations constituted j
material breaches by the Coso parties of their obligations under their contracts with SCE and applicable i
law. The complaint sought termination of the contracts and damages for excess power purchase payments made to the Coso parties. The Coso parties' motion to transfer venue to Inyo County Superior i
Court was granted on August 31,1997. On June 1,1998, the court struck SCE's request for termination l
of the contracts, leaving SCE with its claim for damages and other relief. On February 16,1999, the j
court denied the Coso Parties' motion for judgment on the pleadings directed to SCE's first amended complaint.
j The Coso parties have also asserted various claims against SCE, The Mission Group, and Mission Power Engineering Company (Mission parties) in a cross complaint filed in the action commenced by SCE as well as in a separate action filed against SCE by three of the Coso parties in Inyo County i
Superior Court. in November 1997, the court struck all but two causes of action asserted in the separate l
action on the grounds that they should have been raised as part of the Coso parties' cross-complaint, and j
ordered the remaining two causes of action consolidated for all purposes with the action filed by SCE.
19 1
The Coso parties subsequently filed second and third am nded cross-complaints. Tha third am nded cross-complaint names SCE, the Mission parties, and Edison Intemational. As against SCE, the third amended cross-complaint purports causes of action for declaratory relief, breach of the covenant of good faith and fair dealing; inducing breach of agreements between the Coso parties and their former employees; breach of an earlier settlement agreement between the Mission parties and the Coso parties; slander and disparagement, injunctive relief and restitution for unfair business practices; anticipatory breach of the contracts; and violations of Public Utilities Code ee 453, 702 and 2106. As against the i
I Mission parties, the third amended cross-complaint seeks damages for breach of warranty of authority with respect to the settlement agreement, and for equitable indemnity. The Coso parties voluntarily dismissed Edison international from the third amended cross-complaint on December 4,1998.. As against SCE, the third amended cross-complaint seeks restitution, compensatory damages in excess of
$115 million, punitive damages in an amount not less than $400 million, interest, attomey's fees, declaratory relief, and injunctive relief.
On September 21,1998, SCE filed an answer to the third amended cross-complaint generally denying the allegations contained therein and asserting affirmative defenses. In addition, SCE filed a cross-complaint for reformation of the contracts alleging that if they are not susceptible to SCE's interpretation, they should be reformed to reflect the parties' true intention. The Coso defendants demurred to SCE's j
cross-complaint and, in January 1999, their demurrer was sustained with leave to amend. In light of this new ruling, SCE recently filed an amended cross-complaint for reformation.
Following various pre-trial motions filed by the Mission parties and Edison Intemational, the Coso Parties, on December 23,1998, purported to file a fourth amended cross-complaint against the Mission Parties only. The Mission Parties' demurrer to and motion to strike directed to the fourth amended cross-complaint was heard and taken under submission on March 10,1999.
On December 15,1998, the Court granted the Coso parties leave to file a second amended complaint in the separately filed (now consolidated) action. The second amended complaint which names SCE and Edison International, alleges that SCE engaged in anti-competitive conduct, false advertising, and conduct proscribed by Public Utilities Code e 2106, and seeks injunctive relief, restitution, and punitive damages. On January 20, 1999, SCE filed three motions to strike several portions of the second amended complaint on the grounds, among others, that the CPUC or FERC have either exclusive or primary jurisdiction over the matters asserted therein, and that SCE's alleged conduct was in furtherance of constitutionally protected rights of free speech and petition and therefore not actionable. These matters were heard on February 22,1999, and taken under submission at that time.
Discovery and motion practice related to discovery is active. The Court has set a trial date of March 1, 2000. The materiality of net final judgments against SCE in these actions would be largely dependent on the extent to which any damages or additional payments which might result therefrom are recoverable through rates.
Electric and Magnetic Fields (EMF) Litigation SCE is involved in lawsuits alleging that various plaintiffs developed cancer as a result of exposure to EMF from SCE facilities.
In December 1995, the court granted SCE's motion for summary judgment in the first lawsuit and dismissed the case. Plaintiffs filed a notice of appeal. Following a settlement conference ordered by the Court of Appeal, the case was dismissed in January 1999.
Following dismissal of the second lawsuit by the plaintiffs, a wrongful death action was filed by the husband and children of one of the original plaintiffs who had subsequently died. This wrongful death action was dismissed by the court without leave to amend on September 16,1998. Plaintiffs' appeal in the wrongful death action was dismissed following a settlement conference in the Court of Appeal in January 1999.
20 l
San Onofra Parsonal injury Litigation SCE is actively involved in three lawsuits claiming personal injurios allegedly resulting from exposure to radiation at San Onofre. On August 31,1995, the wife and daughter of a former San Onofre security supervisor sued SCE and SDG&E in the U.S. District Court for the Southern District of California.
Plaintiffs also named Combustion Engineering and the Institute of Nuclear Power Operations as defendants. All trial court proceedings have been stayed pending ruling of the Ninth Circuit Court of Appeal, on an appeal of a lower court's judgment in favor of SCE in two earlier cases raising similar allegations. On May 28,1998, the Court of Appeal affirmed these judgments. A trial date has not yet boon set.
On November 17,1995, an SCE employee and his wife sued SCE in the U.S. District Court for the Southem District of California. Plaintiffs also named Combustion Engineering. The trial in this case resulted in a jury verdict for both defendants. The plaintiffs' motion for a new trial was denied. Plaintiffs filed an appeal of the trial court's judgment to the Ninth Circuit Court of Appeal. Briefing on the appeal was completed in January 1999 and the parties are awaiting a date for oral argument to be set by the court. A decision is not expected until early 2000.
On November 28,1995, a former contract worker at San Onofre, her husband, and her son, sued SCE in the U.S. District Court for the Southem District of Califomia. Plaintiffs also named Combustion Engineering. On August 12,1996, the Court dismissed the claims of the former worker and her husband with prejudice. This case, with only the son as plaintiff, is expected to go to trial in late 1999.
On November 20,1997, a former contract worker at San Onofre and his wife sued SCE in the Superior Court of Califomia, County of San Diego. The case was removed to the U.S. District Court for the Southern District of California. On May 11,1998, the plaintiffs filed a first amended complaint. On May 22,1998, SCE filed an answer denying the material allegations of the first amended complaint. Pursuant to a stipulation of the parties, the court, on January 4,1999, dismissed the plaintiffs' complaint in this matter with prejudice.
In March of 1999, SCE reached an agreement with the plaintiffs in both of the cases at the U.S. District Court level to stay trial pending the results of tha case currently before the Ninth Circuit Court of Appeal.
The parties agreed that if the plaintiffs /pethners do not receive a favorable determination on appeal then the two cases at the District Court leval will be dismissed. If, however, the plaintiffs / petitioners receive a favorable determination on appeal, tSen the two District Court cases will be set for trial.
SCE was previously involved, along with other defendants, in two earlier cases raising allegations similar to those described above. Although, as indicated above, SCE was successful in removing itself from those actions, the impact on SCE, if any, from further proceedings in these cases against the remaining defendants can not be determined at this time.
Mohave Generating Station Environmental Litigation On February 19,1997, the Sierra Club and the Grand Canyon Trust filed suit in the U.S. District Court of Nevada against SCE and the other three co-owners of Mohave Generating Station. The lawsuit alleges that Mohave has been violating various provisions of the CAA, the Nevada state implementation plan, certain EPA orders, and applicable pollution permits relating to opacity and sulfur dioxide emission limits over the last five years. The plaintiffs seek declaratory and injunctive relief as well as civil penalties.
Under the CAA, the maximum civil penalty obtainable is $25,000 per day per violation. SCE and the co-owners obtained an extension to respond to the complaint pending the court's ruling on a motion to dismiss filed by the defendants.
On June 4,1998, the plaintiffs served SCE and its co-owners with a 60-day supplemental notice of intent to sue. This supplemental notice identified additional causes of action as well as an additional plaintiff (National Parks and Conservation Association) to be added to the proceedings. On November 12,1998, the court bifurcated the liability and damage phases of the case.
l 21
r Item 4. Submission cf Matters to a Vots cf Security Holders inapplicable Pursuant to Form 10-K's General Instruction (General Instruction) G(3), the following information is included as an additional item in Part 1:
Executive Officers" of the Registrant Ageet Executive Officer December 31,1998 Company Poelilon John E. Bryson 55 Chairman of the Board, Chief Executive Officer and Director Stephen E. Frank 57 President, Chief Operating Officer and Director Bryant C. Danner 61-Executive Vice President and General Counsel Alan J. Fohrer 48 Executive Vice President and Chief Financial Officer Harold B. Ray 58 Executive Vice President, Generation Business Unit Pamela A. Bass 51 Senior Vice President, Customer Service Business Unit Theodore F. Craver, Jr.
47 Senior Vice President and Treasurer John R. Fielder-53 Senior Vice President, Regulatory Policy and Affairs 1
t Robert G. Foster 51 Senior Vice President, Public Affairs LWiian R. Gorman 45 Senior Vice President, Human Resources Richard M. Rosenblum 48 Senior Vice President, T&D Business Unit l
Bruce C. Foster 46 Vice President, San Francisco Regulatory Affairs Thomas J. Higgins 53 Vice Pres! dent, Corporate Commun' ntions e
Thomas M. Noonan*
47 Vice President and Controller Anthony L. Smith 50 Vice President, Tax Executive Officers are defined by Rule 36-7 of the General Rules and Regulations under the Securities Exchange Act of 1934, as amended. Executive Officers, Bryson, Danner, Fohrer, Craver, Robert Foster, Gorman, Higgins, Noonan and Smith hold the same positions with Edison Intemational. Edison Intemational is the parent holding company of SCE.
Richard K.' Bushey resigned as Vice President and Controller of SCE effective March 1,1999.
None of SCE's executive officers are related to each other by blood or marriage. As set forth in Article IV of SCE's Bylaws, the officers of SCE are chosen annually by and serve at the pleasure of SCE'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 SCE for more than five years except for 22 A
officers who have not held their present position for the past five yens had the following business exper' nce.
e Executive Officer Company Poeltlon Effective Detes Stephen E. Frank President, Chief Operating Officer and June 1995 to present Director President and Chief Operating Officer, August 1990 to January 1995 Florida Power and Light Company'"
Bryant C. Danner Executive Vice President and General June 1995 to present Counsel Senior Vice President and General Counsel July 1992 to May 1995 Alan J. Fohrer Executive Vice President and Chief Financial September 1996 to present Officer Executive Vice President, Chief Financial February 1996 to August 1996 Officer and Treasurer Executive Vice President and Chief Financial May 1995 to January 1996 Officer Senior Vice President and Chief Financial January 1993 to April 1995 Officer Harold B. Ray Executive Vice President, Generation June 1,1995 to present Business Unit Senior Vice President, Power Systems June 1990 to May 1995 Pamela A. Bass Senior Vice President, Customer Service March 1999 to present Business Unit Vee President, Customer Solutions June 1996 to February 1999 Business Unit Vice President, Shared Services January 1996 to May 1996 Division Vee President, ENvest August 1993 to December 1995 Theodore F. Craver, Jr.
Senior Vice President and Treasurer February 1998 to present
~
Vice President and Treasurer September 1996 to February 1998 Executive Vee President and Corporate September 1990 to August 1996 Treasurer, First interstate Bancorp'"
John R. Fielder Senior Vice President, Regulatory Policy and February 1998 to present Affairs Vice President, Regulatory Policy and Public February 1992 to January 1998 Affairs Robert G. Foster Senior Vice President, Public Affairs November 1996 to present Vice President, Public Affairs November 1993 to October 1996 Lillian R. Gorman Senior Vice President, Human Resources March 1999 to present Vice President Human Resources July 1996 to February 1999 Executive Vice President and Human October 1990 to May 1996 Resources Director, First Interstate Bancorp'"
Richard M. Rosenblum Senior Vice President, T&D Business Unit February 1998 to present Vee President, Distribution Business Unit January 1996 to January 1998 Vice President, Nuclear Engineering and June 1993 to December 1995 Technical Services
~
23
Brucs C. Fostar Vice Przeident, Sin Franctco Jinutry 1995 to presint Regulatory Affairs f
Regional Vice President, San Francisco January 1992 to December 1994 Office Thomas J. Higgins Vice President, Corporate Communications April 1995 to present Vice President, Corporate Communications April 1995 to January 1996 President, The Laurel Company""
January 1994 to December 1994 Thomas M. Noonan Vice President and Controller March 1999 to present Assistant Controller September 1993 to February 1999 Anthony L. Smith Vice President, Tax March 1999 to present Assistant Controller January 1998 to February 1999 (1) This entity is not a parent, subsidiary or other affiliate of SCE.
(2) As President of The Laurel Company, Thomas J. Higgins provided advice on planning and financing for mergers and acquisitions for clients in the managed health care business.
)
j 24 l
PARTll Item 5. Market for Registrant's Common Equity and R91sted Stockholder Matters Certain information responding to item 5 with respect to frequency and amount of cash dividends is e
included in SCE's Annual Report to Shareholders for the year ended December 31,1998, (Annual Report) under " Quarterly Financial Data" on page 35 and is incorporated by reference pursuant to General Instruction G(2). As a result of the formation of a holding company described above in Item 1, all of the issued and outstanding common stock of SCE is owned by Edison international and there is no market for such stock.
Item 6.
Selected Financial Data Information responding to item 6 is included in the Annual Report under " Selected Financial and Operating Data: 1994-1998 on page 38 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 of Results of Operations and Financial Condition" on pages 1 through 12 and is incorporated herein by reference pursuant to General instruction G(2).
Item 7A. Quantitative and Qualitative Disclosures About Market Risk information responding to item 7A is included in the Annual Report under " Management's Discussion and Analysis of Results of Operations and Financial Condition" on pages 4 through 5 and is incorporated herein by reference to General Instruction G(2).
l Item 8.
Financial Statements and Supplementary Data j
Certain information responding to item 8 is set forth after item 14 in Part IV. Other informaton responding to item 8 is inc'uded in the Annual Report on pages 13 through 35, and is incorporated herein by reference pursuant to General Instruction G(2).
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.
PART lil item 10. Directors and Executive Officers of the Registrant Information conceming executive officers of SCE 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 t
connection with SCE's Annual Meeting to be held on April 15,1999, under the heading, " Election of Directors of Edison international and SCE" on pages 4 through 7 and "Section 16(a) Beneficial Ownership Reporting Compliance" on page 23, and is incorporated herein by reference pursuant to l
GeneralInstruction G(3).
25
)
item 11. Executivo Compensation Information responding to item 11 is included in the Proxy Statement beginning with the section under the heading " Executive Compensation Table - Edison Interna %nal and SCE" on pages 10 through 22, 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 " Stock Ownership of Directors and Executive Officers of Edison Intemational and SCE" on pages 8 through 9 and " Stock Ownership of Certain Shareholders" on page 26, 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 "Certain Relationships and Transactions of Nominees and Executive Officers" on page 23 and is incorporated herein by reference pursuant to General Instruction G(3).
PART IV ltem 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K (a)
(1)
Financial Statements The following items contained in the 1998 Annual Report to Shareholders are incorporated by reference in this report.
Manageraent's Discussion and Analysis of Rewits of Operations and Financial Condition Conse'idated Statements of income - Years Ended December 3' 1998, 1997 and 1996 Consolidated Statements of Retained Eamings -- Years Erded December 31,1998,1997 and 1996 Consolidated Balance Sheets - December 31,1998, and 1997 ConsolidaH Statement? of Cash Flows -- Years Ended December 31,1998,1997 and 1996 Notes to Cc e & lated Financial Statements Responsibility for Financial Reporting Report of Independent Public Accountants (M
Report of Independent Public Accountants and Scheduiss Supplementing Financial Statements The following documents may be found in this report at the indicated page numbers.
EG91 Report of Independent Public Accountants on Supplemental Schedules..............................................................................................
28 Schedule Il--Valuation and Qualifying Accounts for the Years Ended December 31,1997,1996 and 1995...............
29 26
Schedules I through V, inclusiva, except those referred ts abov2, ara omitted as not required or not applicable.
.(3)
Exhibits See Exhibit Index on page 35 of this report.
(b) Floports on Form 8-K November 13,1998 Item 5: CXher Events Proposition 9 1
27
REPORT OF WWEPENDENT PUBUC ACCOUNTANTS o, __ _<.S To Southem Camomia Edson Company:
We have audited in accordance with generally accepted auditing standrAs, the consolidated financial statunents included in the 1998 Annual Report to Shareholders of Southem Califomia Edson Company (SCE) incorporated by reference in this Form 10-K, and have issued our report thereon dated Fetzuery4,1999. Our audts of the consoudsted financial statements were made for the purpose of formng an opinion on those basic coneoudated Anancial statements taken as a whole. The supplemental schedules Ested in Part IV of this Form 10-K, which are the responsbEky of SCE's management, are presented for purposes of coniplyme with the Securthes and Exchange Commission's rules and readmeions, and are not part of the basic cor=aMaeed financial statements. These supplemental schedules have been subjected to the audting procedures appled in the audts of the basic consoldated financial statements and, in our opinion, fairly state in al6 material raapar+= the financial data requwed to be set forththerein in relation to the basic consolidated fimncial statements taken as a whole, I
\\
\\
w THUR ANDERSEN LLP Los Angeles, Camomia Febuary 4,1990 9
28
SOUTHERN CALIFORNIA EDISON COMPANY SCHEDULE 11-VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31,1998 Additione Balance at Charged to Charged to Balance Beginning of Coote and other atEnd Desorlotion EEhtd Exoenees Accounts Dodvotions of Period (in thousande)
Group A:
Uncolectible accounts-Custorners
$ 24,245
$ 19,808
$ 24,457
$19,596 AI other 2.208 2,273 1,847 2,634 Total
$ 26,453
$ 22,081
$ 26,304 (a)
$ 22,230 Group B:
DOE Decontamination and Decommissioning
$ 44,336
$ (89)(b)
$ 4,828 (c)
$ 30,419 Purchased-power settlements 145,640 15,943 (d) 129,697 Peneb and beno6ts 211,200
$170,743 18,988 (e) 161,263 (f) 239,668 insurance, casualty and other 78,461 69,275 74,487(g) 73,249 Total
$479,637
$240,018
$ 18,899
$256,521
$482,033
(:)
Accounts written off, not.
(b)
Represents revision to estimate based on actual billings.
(c)
Represents amounts paid.
(d)
Represents the amort!zation of the liability established for purchased-power contract settlement agreements.
(:)
Primarily represents transfers from the accrued paid absence allowance account for required additions to the comprehensive disability plan accounts.
(f) includes pension payments to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.
(g)
Amounts charged to operations that were not cove ~ ed by insurance.
r 29
c-SOUTHERN CALIFORNIA EDISON COMPANY SCHEDULE 11-VALUATION AND QUALIFYING ACCOUNTS For the Year Ended December 31,1997 Additions Balance et Charged to Charged to Balance Beginning of Costs and Other et End Desortation Period Expenses Accounts Deductions of Period (in thousande)
Group A:
Uncollectible accounts-Custorners
$ 24,390
$ 20,597
$ 20,742
$ 24,245 All other 1,689 1,180 661 2,208 Total
$ 26,079
$ 21,777
$ 21,403(a)
$ 26,453 Group B:
DOE Decontamination and Decommissioning
$ 48,789
$ 1,089(b)
$ 5,542(c)
$ 44,336 Purchased-power settlements 107,700 67,320(d) 29,380(e) 145,640 Pension and tvmefits 180,927
$102,193 17,624(t) 89,544(g) 211,200 Insurance, casualty and other 86,509 57,749 65,797(h) 78,461 Total
$423,925
$159,942
$ 86,033
$190,263
$479,637 (a)
Accounts written off, not.
(b)
Represents revision to estimate based on actual billings, (c)
Represents amounts paid, (d)
Represents additional payments to be made under agreements to terminate purchased-power contract.
(e)
Represents the amortization of the liability established for purchased-power contract settlement agreements.
(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.
30
W i
l SOUTHERN CALIFIRNIA EDISON C3MPANY SCHEDULE 11-VALUATION AND QUALIFYlNG ACCOUNTS For the Year Ended December 31,1996 13 - - -
Balance at Charged to Charged to Balance Beginning of coetsand other at End Deoorlotion Period Expenses Accounto Deductione of Period (in thousande)
Group A:
UncoHectble accounts-CusWners
$ 22.126
$ 21,831
$ 19,567
$ 24,300 AN othes 2,013 376 700 1,689
$ 24,1N
$ 22,207
$ 20.267(a)
$ 26,079 Total Group B:
DOE Decontamination and Decommissioning
$ 52,742
$ 1,468(b)
$ 5,5421(c)
$ 48,789 Purchased-power settlemunts 107,700(d) 107,700 Pension and benefits 196,662 8.547 21,869(e) 46,151(f) 180,927 Insurance, casualty and other 94,788 59,123 67,402(g) 86,509 Total
$344,192
$ 67,670
$131,037
$118,974
$423,925 (t)
Accounts written off, net.
(b)
Represents revision to estimate based on actual billings.
(c)
Represents amounts paid.
(d)
Represents payments to be made under an agreement to terminate a purchased-power contract.
(5)
Primarily represents transfers from the accrued paid absence allowance account for required additions to the comprehensive disability plan accounts.
(f) includes pension paymonts to retired employees, amounts paid to active employees during periods of illness and the funding of certain pension benefits.
(g)'
Amounts charged to operations that were not covered by insurance.
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i 1
CGNATURED Pursuant to the requirements of Sechon 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused ttis report to be si ned on its behalf by the undersagned, thereunto duly 9
authorized.
SOUTHERN CALIFORNIA EDISON COMPANY Y
b.
Kenneth S. Stewart Assistant GeneralCounsel Date: March 24,1999 Pursuant to the requirements of the Securities Exchan9e Act of 1934, this report has been signed below by the fogowing persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature IlUn Dgg Principal Executive Officer:
John E. Bryson*
Chairman of the Board, March 24,1999 Chief Executive Officer and Drector Principal Financial Officer:
Alan J. Fohrer*
Executive Vice President March 24,1999 and Chief FinancialOfficer Contro5er or Pnncipal Accountin9 Officer:
Thomas M. Noonan*
Vice President and March 24,1999 Controller Board of Directors:
Winston H. Chen*
Director March 24,1999 Warren Christopher
- Dwoctor March 24,1999 Stephen E. Frank
- Drector March 24,1999 Joan C. Hanley*
Director March 24,1999 Cad F. Huntsinger*
Drector March 24,1999 Charles D. M81er*
Director March 24,1999 Luis G. Nogales*
Drector March 24,1999 Ronald L Olson*
Drector March 24,1999 James M. Rosser" Director March 24,1999 E. L Shannon, Jr.*
Drector March 24,1999 i
Robert H. Smith
- Director March 24,1999 Thomas C. Sutton*
Director March 24,1999 j
Daniel M. Tellep*
Drector March 24,1999 James D. Watkins*
Director March 24,1999 Edward Zapanta*
Director March 24,1999 l
M 6. &
- sy Kenneth S. Stewart Assistant GeneralCounsel 32
EXHIBlT INDEX Exhibit Number Description 3.1 Certificate of Amendment and Restated Articles of Incorporation of SCE effective June 1, 1993 (File No.1-2313, Form 10-K for the year ended December 31,1993)*
3.2 Certificate of Correction of Restated Articles of Incorporation of SCE dated June 23,1997 (File No.1-2313, Form 10-Q for the quarter ended September 30,1997)*
3.3 Bylaws of SCE as adopted by the Board of Directors on February 18,1999 4.1' SCE First Mortga0e Bond 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 Third Supplemental Indenture, dated as of June 24,1935 (Registration No. 2-1602)*
4.4 Fourth Supplemental Indenture, dated as of September 1,1935 (Registration No. 2-4522)*
4.5 Fifth Supplemental Indenture, dated as of August 15,1939 (Registration No. 2-4522)*
4.6 Sixth Supplementa! Indenture, dated as of September 1,1940 (Registration No. 2-4522)*
4.7 Eighth Supplemental Indenture, dated as of August 15,1948 (Registration No. 2 7610)*
4.8 Twenty-Fourth Supplemental ladenture, dated as of February 15,1964 (Registration No.
2-22056)*
4.9 Eighty-Eighth Supplemental Indenture, dated as of July 151992 (File No.12313, Form 8-K dated July 22,1992)*
10.1 1981 Deterred Compensation A0reement (File No.1-2313, Form 10-K for the year ended December 31,1981)*
10.2 1985 Deferred Compensation Agreement for Executives (File No.1-2313, Form 10-K for the year ended December 31,1986)*
10.3 1985 Deferred Compensation A0reement for Directors (File No.1-2313, Form 10-K for the year ended December 31,1986)*
10.4 Director Deferred Compensation Plan (File No.12313, Form 10-Q for the quarter ended June 30,1998)*
10.5 Director Grantor Trust Agreement (File No.1-9936, Form 10-K for the year ended December 31,1995)*
10.6 Executive Deferred Compensation Plan (File No.1 2313, Form 10-Q for the quarter ended March 31,1998)*
10.7 Executive Grantor Trust A reement (File No.1-2313, Form 10-K for the year ended 0
December 31,1995)*
10.8 Executive Supplemental Benefit Program (File No.1-2313, Form 10-K for the year ended December 31,1980)*
10.9 Executive Retirement Plan (File No.12313, Form 10-K for the year ended December 31, 1995)*
10.10 Executive incentive Compensation Plan (File No.1-2313, Fomi 10-K for the year ended December 31,1997)*
10.11 Executive Disability and Survivor Benefit Program (File No.1-2313, Form 10-K for the year ended December 31,1994)*
10.12 Retirement Plan for Directors (File No.1-2313, Form 10-0 for the quarter ended June 30, 1998)*
10.13 Officer Long-Term incentive Compensation Plan (File No.1-2313, Form 10-Q for the quarter ended March 31,1998)*
10.13.1 Form of Agreement for 1989-1995 Awards under the Officer Long-Term incentive Compensation Plan (File No.1-2313, Form 10-K for the year ended December 31,1995)*
10.13.2 Form of Agreement for 1996 Awards under the Officer Long-Term incentive Compensation Plan (File No.1-2313, Form 10-K for the year ended December 31,1996)*
33
1 Exhibit i
l Number Description 10.13.3 Form of Agreement for 1997 Awards under the Officer and Management Lo,,9-Term incontive Compensation Plans (File No.1-2313, Form 10-K for the year ended December 31, 1997)*
10.14 Equity Compensation Plan (File No.1-2313, Form 10-Q for the quarter ended June 30, 1998)*
10.14.1 Form of Agreement for 1998 Employee Awards under the Equity Compensation Plan (File No.1-2313, Form 10-Q for the quarter ended June 30,1998)*
10.14.2 Form of Agreement for 1998 Director Awards under the Equity Compensation Plan (File No.
1-2313, Form 10-Q for the quarter ended June 30,1998)*
10.15 Estate and Financial Planning Program (File No.1-2313, Form 10-K for the year ended December 31,1995)*
10.16 Option Gain Deferral Plan (File No.1-2313, Form 10-0 for the quarter ended March 31, 1998)*
10.17 Employment Letter Agreement with Bryant C. Danner (File No.1-2313, Form 10-K for the year ended December 31,1992)*
10.18 Employment Letter Agreement with Stephen E. Frank (File No.1-2313, Form 10-K for the year ended December 31,1995)*
10.19 Election Terms for Warren Christopher (File No.1-2313, Form 10-K for the year ended December 31,1997)*
10.20 Dispute resolution amendment of 1981 Executive Deferred Compensation Plan,1985 Executive and Director Deferred Compensation Plans and Executive Supplemental Benefit Program 10.21 Retirement Agreement with Richard K. Bushey 12.
Computation of Ratios of Eamings to Fixed Charges 13.
Annual Report to Shareholders for year ended December 31,1997 23.
Consent of Independent Public Accountants - Arthur Andersen LLP 24.1 Powerof 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.
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