ML13309A435
| ML13309A435 | |
| Person / Time | |
|---|---|
| Site: | San Onofre  |
| Issue date: | 12/31/1997 |
| From: | Andersen A, Bryson J, Bushey R Southern California Edison Co |
| To: | |
| Shared Package | |
| ML13309A436 | List: |
| References | |
| NUDOCS 9806220265 | |
| Download: ML13309A435 (47) | |
Text
AnEIS\\ETT\\\\I\\
O N 1997 Annual Report 2060 onP
A Profile of Southern California Edison Company Southern California Edison (SCE) is one of the nation's largest electric utilities.
Headquartered in Rosemead, California, SCE is a subsidiary of Edison International, which is primarily an energy-services company.
SCE, a 111-year-old investor-owned utility, serves 4.3 million customers in Central and Southern California. More than 11 million people live in its 50,000-square-mile service territory.
Contents 1
Selected Financial and Operating Data: 1993-1997 2
Management's Discussion and Analysis of Results of Operations and Financial Condition 15 Consolidated Financial Statements 19 Notes to Consolidated Financial Statements 40 Quarterly Financial Data 41 Responsibility for Financial Reporting 42 Report of Independent Public Accountants 43 Board of Directors 43 Management Team
Selected Financial and Operating Data: 1993-1997 Southern California Edison Company Dollars in millions 1997 1996 1995 1994 1993 Income statement data:
Operating revenue
$ 7,953
$ 7,583
$ 7,873
$ 7,799
$ 7,397 Operating expenses 6,893 6,450 6,724 6,705 6,232 Fuel and purchased power expenses 3,735 3,336 3,197 3,403 3,290 Income tax from operations 582 578 560 508 506 Allowance for funds used during construction 17 25 34 29 36 Interest expense -
net 444 453 464 443 449 Net income 606 655 680 639 678 Earnings available for common stock 576 621 643 599 637 Ratio of earnings to fixed charges 3.49 3.54 3.52 3.43 3.39 Balance sheet data:
Assets
$18,059
$17,737
$18,155
$18,076
$18,098 Gross utility plant 21,483 21,134 20,717 20,127 19,441 Accumulated provision for depreciation and decommissioning 10,544 9,431 8,569 7,710 7,138 Common shareholder's equity 3,958 5,045 5,144 5,039 4,932 Preferred stock:
Not subject to mandatory redemption 184 284 284 359 359 Subject to mandatory redemption 275 275 275 275 275 Long-term debt 6,145 4,779 5,215 4,988 5,234 Capital structure:
Common shareholders equity 37.5%
48.6%
47.1%
47.3%
45.7%
Preferred stock:
Not subject to mandatory redemption 1.7%
2.7%
2.6%
3.3%
3.3%
Subject to mandatory redemption 2.6%
2.7%
2.5%
2.6%
2.5%
Long-term debt 58.2%
46.0%
47.8%
46.8%
48.5%
Operating data:
Peak demand in megawatts (MW) 19,118 18,207 17,548 18,044 16,475 Generation capacity at peak (MW) 21,511 21,602 21,603 20,615 20,606 Kilowatt-hour sales (kWh) (in millions) 77,234 75,572 74,296 77,986 73,308 Average annual kWh sales per residential customer 6,399 6,322 6,188 6,259 6,070 Total energy requirement (kWh) (in millions) 86,849 84,236 81,924 85,011 81,328 Energy-mix:
Thermal 44.7%
47.6%
51.6%
59.5%
53.8%
Hydro 6.5%
6.9%
7.7%
3.9%
7.3%
Purchased power and other sources 48.8%
45.5%
40.7%
36.6%
38.9%
Customers (in millions) 4.25 4.22 4.18 4.15 4.12 Full-time employees*
12,642 12,057 14,886 16,351 16,585
- 1993-1994 are based on twelve-month averages.
1
Management's Discussion and Analysis of Results of Operations and Financial Condition In the following Management's Discussion and Analysis of Results of Operations and Financial Condition and elsewhere in this annual report, the words estimates, expects, anticipates, believes, and other similar expressions are intended to identify forward-looking information 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 setting rates and implementing 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; and other unforeseen events.
Results of Operations Earnings Southern California Edison Company's (SCE) 1997 earnings were $576 million, compared with $621 million in 1996 and $643 million in 1995. SCE's earnings include special charges of $18 million in 1996 for workforce management costs and reserves, and $15 million in 1995 for workforce management expenses. Before special charges, earnings declined $63 million in 1997 from the prior year, mainly due to the extended outage and lower return at the San Onofre Nuclear Generating Station. The decline was partially offset by higher sales and lower non-nuclear operating expenses. The $19 million decrease in 1996 earnings from 1995 (excluding nonrecurring charges) is mainly attributable to a reduction in authorized rates of return and authorized operating expenses, partially offset by improved operating performance.
Operating Revenue Operating revenue increased 5% over 1996, due to an increase in sales volume and customer refunds in 1996. There were no comparable refunds in 1997. The increase in volume is mainly attributable to the overall increase in retail sales among residential and commercial customers. Operating revenue in 1996 decreased 4% from 1995, as increased sales volume was more than offset by lower average rates. The lower rates were attributable to the California Public Utilities Commission's (CPUC) decision to lower SCE's 1996 authorized revenue by 4.4%. Additionally, during 1996, SCE's customers received a one time bill credit totaling $237 million as part of a CPUC-ordered refund of energy cost balancing account overcollections. In 1997, over 98% of SCE's operating revenue was from retail sales. Retail rates are regulated by the CPUC and wholesale rates are regulated by the Federal Energy Regulatory Commission (FERC).
Due to warm weather during the summer months, operating revenue during the third quarter of each year is significantly higher than the other quarters.
The changes in operating revenue resulted from:
In millions Year ended December 31, 1997 1996 1995 Operating revenue Rate changes (including refunds) 173
$ (522) 168 Sales volume changes 193 206 (129)
Other 4
26 35 Total 370
$ (290) 74 Legislation enacted in September 1996 provided for, among other things, at least a 10% rate reduction (financed through the issuance of rate reduction notes) for residential and small commercial customers in 1998 and other rates to remain frozen at the June 10, 1996, level (system average of 10.10 per kilowatt hour). See discussion in Competitive Environment.
2
Southern California Edison Company Operating Expenses Fuel expense increased 40% in 1997. The increase is primarily due to a $174 million gas contract termination payment during the third quarter, combined with higher gas prices and the extended refueling outages at San Onofre. San Onofre Unit 2 was shut down during the entire first quarter of 1997, Unit 3 was shut down 80 days of the second quarter and both units had a combined outage time of 30 days during the third quarter, which resulted in an overall increase in gas-powered generation for the year.
There were no comparable outages in 1996. Fuel expense increased 11% in 1996, compared to 1995, due to higher gas prices and changes in the fuel mix.
Purchased-power expense increased slightly in 1997 and 1996, due to increases in spot market purchases and increases in power purchased under federally mandated contracts. SCE is required under federal law to purchase power from certain nonutility generators even though energy prices under these contracts are generally higher than other sources. In 1997, SCE paid about $1.6 billion (including energy and capacity payments) more for these power purchases than the cost of power available from other sources. The CPUC has mandated the prices for these contracts.
Provisions for regulatory adjustment clauses decreased substantially in 1997, due to undercollections in the energy cost balancing account as actual energy costs (including the gas termination payments discussed above) exceeded CPUC-authorized fuel and purchased-power cost estimates. In addition, there were undercollections associated with SCE's direct access activities (see discussion in Competitive Environment -
Direct Customer Access), research and development activities and San Onofre. These undercollections were offset by overcollections related to actual base-rate revenue from kilowatt-hour sales exceeding CPUC-authorized estimates and the final settlement of SCE's Canadian supply and transportation contracts (see discussion in Regulatory Matters). The provisions for regulatory adjustment clauses also decreased in 1996 from 1995 due to lower than authorized base-rate revenue, undercollections related to the accelerated recovery of SCE's remaining investment in San Onofre Units 2 and 3, and the $237 million refund to ratepayers during 1996 for prior energy cost balancing account overcollections.
Maintenance expense increased 23% in 1997, due to increased maintenance costs for the scheduled refueling outages at the San Onofre units and SCE's transmission and distribution operating facilities.
Depreciation and decommissioning expense increased 17% in 1997. The increase is due to increases in plant assets and the accelerated recovery of the Palo Verde Nuclear Generating Station units effective January 1997. Depreciation and decommissioning expense increased 12% in 1996, compared to 1995, due to higher depreciation rates and the accelerated recovery of San Onofre Units 2 and 3 starting in April 1996.
Property and other taxes decreased 32% in 1997, due to a reclassification of payroll taxes to operation and maintenance expense.
Other Income and Deductions The provision for rate phase-in plan reflects a CPUC-authorized, 10-year rate phase-in plan, which deferred the collection of revenue during the first four years of operation for the Palo Verde units. The deferred revenue (including interest) was collected evenly over the final six years of each unit's plan. The plan ended in February 1996, September 1996 and January 1998 for Units 1, 2 and 3, respectively. The provision is non-cash offset to the collection of deferred revenue.
Interest and dividend income increased 18% in 1997, due to increases in interest earned on SCE's balancing accounts and increases in dividend income from its equity investments.
3
Management's Discussion and Analysis of Results of Operations and Financial Condition Other nonoperating income decreased substantially in 1997, due to additional accruals for regulatory matters associated with the restructuring of California's electric utility industry.
Other nonoperating income also decreased in 1996, compared to 1995, due to regulatory accruals in 1996.
Interest Expense Interest on long-term debt decreased 9% in 1997, due to the early retirement of $400 million of first and refunding mortgage bonds in July 1997, partially offset by additional interest expense associated with the issuance of approximately $2.5 billion in rate reduction notes in December 1997 (see discussion in Cash Flows from Financing Activities).
Other interest expense increased in 1997, due to higher levels of short-term debt used to retire first and refunding mortgage bonds, discussed above. Other interest expense decreased in 1996 from 1995, due to the lower levels of short-term debt and lower interest rates.
Financial Condition SCE's liquidity is primarily affected by debt maturities, dividend payments and capital expenditures.
Capital resources include cash from operations and external financings.
Edison International's Board of Directors has authorized the repurchase of up to $2.3 billion of its outstanding shares of common stock. Edison International has repurchased 76.9 million shares ($1.7 billion) between January 1995 and January 30, 1998, funded by dividends from its subsidiaries and its lines of credit.
SCE's cash flow coverage of dividends during 1997 decreased to 0.9 times from 2.2 times in 1996 and 3.5 times in 1995 as a result of a $1.2 billion special dividend SCE paid to Edison International from the rate reduction note proceeds received in December 1997.
Cash Flows from Operating Activities Net cash provided by operating activities totaled $1.7 billion in 1997, $1.8 billion in 1996 and $2.0 billion in 1995. Cash from operations exceeded capital requirements for all years presented.
Cash Flows from Financing Activities Short-term debt is used to finance fuel inventories, balancing account undercollections and general cash requirements. Long-term debt is used mainly to finance capital expenditures. External financings are influenced by market conditions and other factors, including limitations imposed by its articles of incorporation and trust indenture. As of December 31,1997, SCE could issue approximately $10.4 billion of additional first and refunding mortgage bonds and $5.3 billion of preferred stock at current interest and dividend rates.
At December 31, 1997, SCE had available lines of credit of $1.8 billion, with $1.3 billion for general purpose short-term debt and $500 million for the long-term refinancing of its variable-rate pollution-control bonds. These unsecured lines of credit are at negotiated or bank index rates with various expiration dates; the majority have five-year terms.
California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates. Additionally, the CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International. At December 31, 1997, SCE had the capacity to pay $1.4 billion in additional dividends and continue to maintain its authorized capital structure.
4
Southern California Edison Company In December 1997, SCE Funding LLC, a special purpose entity (SPE), of which SCE is the sole member, issued approximately $2.5 billion of rate reduction notes to Bankers Trust Company of California, as certificate trustee for the California Infrastructure and Economic Development Bank Special Purpose Trust SCE-1 (Trust), which is a special purpose entity established by the State of California. The terms of the rate reduction notes generally mirror the terms of the pass-through certificates issued by the Trust, which are known as rate reduction certificates. The proceeds of the rate reduction notes were used by the SPE to purchase from SCE an enforceable right known as transition property. Transition property is a current property right created pursuant to the restructuring legislation and a financing order of the CPUC and consists generally of the right to be paid a specified amount from a non-bypassable tariff levied on residential and small commercial customers. Notwithstanding the legal sale of the transition property by SCE to the SPE, the amounts reflected as assets on SCE's balance sheet have not been reduced by the amount of the transition property sold to the SPE, and the liabilities of the SPE for the rate reduction notes are for accounting purposes reflected as long-term liabilities on the consolidated balance sheet of SCE. SCE used the proceeds from the sale of the transition property to retire debt and equity securities.
The rate reduction notes have maturities ranging from one to 10 years, and bear interest at rates ranging from 5.98% to 6.42%. The rate reduction notes are secured solely by the transition property and certain other assets of the SPE, and there is no recourse to SCE or Edison International.
Although the SPE is consolidated with SCE in the financial statements, as required by generally accepted accounting principles, the SPE is legally separate from SCE, the assets of the SPE are not available to creditors of SCE or Edison International, and the transition property is legally not an asset of SCE or Edison International.
Cash Flows from Investing Activities The primary uses of cash for investing activities are additions to property and plant and funding of nuclear decommissioning trusts. Decommissioning costs are accrued and recovered in rates over the term of each nuclear generating facility's operating license through charges to depreciation expense. SCE estimates that it will spend approximately $12.7 billion between 2013 -
2070 to decommission its nuclear facilities. This estimate is based on SCE's current-dollar decommissioning costs ($2.1 billion), escalated using a 6.65% annual rate. These costs are expected to be funded from independent decommissioning trusts which receive SCE contributions of approximately $100 million per year until decommissioning begins.
Market Risk Exposures SCE's primary market risk exposures arise from fluctuations in energy prices and interest rates. SCE's risk management policy allows the use of derivative financial instruments to manage its financial exposures, but prohibits the use of these instruments for speculative or trading purposes.
SCE has hedged a portion of its exposure to increases in natural gas prices. Increases in natural gas prices tend to increase the price of electricity purchased from the power exchange (PX). SCE's exposure is also limited by regulatory mechanisms that protect SCE from much of the risk arising from high electricity prices.
A 10% increase in market interest rates would result in a $6 million increase in the fair value of SCE's interest rate hedge agreements. A 10% decrease in market interest rates would result in a $6 million decline in the fair market value of interest rate hedge agreements. A 10% increase in natural gas prices would result in a $26 million increase in the fair market value of gas call options. A 10% decrease in natural gas prices would result in a $17 million decline in the fair market value of gas call options. A 10%
change in market rates is expected to have an immaterial effect on SCE's other financial instruments.
5
Management's Discussion and Analysis of Results of Operations and Financial Condition Projected Capital Requirements SCE's projected construction expenditures for the next five years are: 1998 -
$956 million; 1999 -
$807 million; 2000 -
$763 million; 2001 -
$721 million; and 2002 -
$671 million.
Long-term debt maturities and sinking fund requirements for the next five years are: 1998 -
$693 million; 1999 -
$401 million; 2000 -
$571 million; 2001 -
$646 million; and 2002 -
$446 million.
Preferred stock redemption requirements for the next five years are: 1998 through 2001 -
zero and 2002 -
$105 million.
Regulatory Matters Legislation enacted in September 1996 provided for, among other things, a 10% rate reduction for residential and small commercial customers in 1998 and other rates to remain frozen at the June 10, 1996, level (system average of 10.10 per kilowatt-hour). See further discussion in Competitive Environment -
Restructuring Legislation.
In 1998, revenue will be affected by various mechanisms depending on the utility operation. Revenue related to distribution operations will be determined through a performance-based rate-making mechanism (PBR) (see discussion in Competitive Environment -
PBR) and the distribution assets will have the opportunity to earn a CPUC-authorized 9.49% return. Until the independent system operator (ISO) begins operation, transmission revenue will be determined by the same mechanism as distribution operations. After that time, transmission revenue will be determined through FERC-authorized rates and transmission assets will earn a 9.43% return. These rates are subject to refund. See discussions in the Competitive Environment -
Rate-setting and FERC Restructuring Decision sections.
Revenue from generation-related operations will be determined through the competition transition charge (CTC) mechanism, nuclear rate-making agreements and the competitive market. Revenue related to fossil and hydroelectric generation operations will be recovered from two sources. The portion that is made uneconomic by electric industry restructuring will be determined through the CTC mechanism. The portion that is economic will be recovered through the PX mechanism. In 1998, fossil and hydroelectric generation assets will earn a 7.22% return. A more detailed discussion is in Competitive Environment CTC.
The CPUC has authorized revised rate-making plans for SCE's nuclear facilities, which call for the accelerated recovery of its nuclear investments in exchange for a lower authorized rate of return. SCE's nuclear assets are earning an annual rate of return of 7.35%. In addition, the San Onofre plan authorizes a fixed rate of approximately 40 per kilowatt-hour generated for operating costs including incremental capital costs, and nuclear fuel and nuclear fuel financing costs. The San Onofre plan commenced in April 1996, and ends in December 2001 for the accelerated recovery portion and in December 2003 for the incentive pricing portion.
Palo Verde's operating costs, including incremental capital costs, and nuclear fuel and nuclear fuel financing costs, are subject to balancing account treatment. The Palo Verde plan commenced in January 1997 and ends in December 2001.
Beginning January 1, 1998, both the San Onofre and Palo Verde rate-making plans became part of the CTC mechanism.
The changes in revenue from the regulatory mechanisms discussed above, excluding the effects of other rate actions, is expected to have a minimal impact on 1998 earnings. However, the issuance of the rate reduction notes in December 1997, which enables the repurchase of debt and equity, will have a negative impact on 1998 earnings of approximately $97 million.
In 1994, SCE filed its testimony in the non-Qualifying Facilities (QF) phase of the 1994 Energy Cost Adjustment Clause proceeding. In 1995, the CPUC's Office of Ratepayer Advocates (ORA) filed its report on the reasonableness of SCE's gas supply costs for both the 1993 and 1994 record periods. The 6
Southern California Edison Company report recommends a disallowance of $13 million for excessive costs incurred from November 1993 through March 1994 associated with SCE's Canadian gas purchase and supply contracts. The report requested that the CPUC defer finding SCE's Canadian supply and transportation agreements reasonable for the duration of their terms and that the costs under these contracts be reviewed on a yearly basis. In 1996, the ORA issued its report for the 1995 record period recommending a $38 million disallowance for excessive costs incurred from April 1994 through March 1995. Both proposed disallowances were later consolidated into one proceeding. On December 3, 1997, the CPUC approved a settlement agreement between SCE and the ORA on this and any future issues, which will result in a
$61 million (including interest) refund to SCE's customers. The refund which is fully reflected in the financial statements will be made in first quarter 1998.
In 1991, SCE filed its testimony in the QF phase of the 1991 Energy Cost Adjustment Clause proceeding.
In 1993, the ORA filed its report on the reasonableness of SCE's QF contracts and alleged that SCE had imprudently renegotiated a QF contract with the Mojave Cogeneration Company.
The report recommended a disallowance of $32 million (1993 net present value) over the contract's 20-year life.
Subsequently, SCE and the ORA reached a settlement where SCE agreed to a one-time reduction to its energy cost adjustment clause balancing account of $14 million plus interest.
In October 1996, the CPUC approved the settlement agreement, subject to SCE and the ORA accepting certain conditions concerning the way the $14 million payment would be reflected in rates. After reviewing the decision, SCE declined to accept the condition proposed by the CPUC and in November 1996 filed an application for rehearing. In February 1997, the CPUC denied SCE's application. Because SCE and the ORA were unable to finalize their settlement, hearings on the ORA's disallowance recommendations were held in June 1997. During the hearings, the ORA presented testimony to update its assessment of ratepayer harm, which it now estimates to be $45 million (1997 net present value) over the contract's life. In November 1997, a CPUC administrative law judge (ALJ) issued a proposed decision which would adopt the ORA's $45 million disallowance. In January 1998, the CPUC withdrew the ALJ's proposed decision pending oral arguments. Oral arguments were heard on February 4, 1998, at which time SCE requested an alternate proposed decision be issued. SCE expects this matter to be returned to the CPUC's agenda in the near future and a final decision to be issued during second quarter 1998. SCE cannot predict the final outcome of this matter but does not believe it will materially affect its results of operations.
Competitive Environment SCE currently operates in a highly regulated environment in which it has an obligation to deliver electric service to customers in return for an exclusive franchise within its service territory. This regulatory environment is changing.
The generation sector has experienced competition from nonutility power producers and regulators are restructuring California's electric utility industry.
California Electric Utility Restructuring Restructuring Legislation -
In September 1996, the State of California enacted legislation to provide a transition to a competitive market structure. The legislation substantially adopted the CPUC's December 1995 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.
Transition costs related to power-purchase contracts would be recovered through the terms of their contracts while most of the remaining transition costs would be recovered through 2001. The legislation also included provisions to finance a portion of the stranded costs that residential and small commercial customers would have paid between 1998 and 2001, which would allow SCE to reduce rates by at least 10% to these customers, beginning January 1, 1998. The financing would occur with securities issued by the California Infrastructure and Economic Development Bank, or an entity approved by the Bank. The legislation included a rate freeze for all other customers, including large commercial and industrial customers, as well as provisions for continued funding for energy conservation, low-income programs and renewable resources. Despite the rate freeze, SCE expects to be able to recover its revenue requirement during the 1998-2001 transition period.
In addition, the legislation mandated the 7
Management's Discussion and Analysis of Results of Operations and Financial Condition implementation of the CTC that provides utilities the opportunity to recover costs made uneconomic by electric utility restructuring. Finally, the legislation 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 May 1997, SCE filed an application with the CPUC requesting approval of the issuance of an aggregate amount of up to $3 billion of rate reduction notes in one or more series or classes and a 10% rate reduction for the period from January 1, 1998, through March 31, 2002. At the same time, SCE filed an application with the California Infrastructure and Economic Development Bank for approval to issue the notes. Residential and small commercial customers will repay the notes over the expected 10-year term through non-bypassable charges based on electricity consumption. In December 1997, after receiving approval from both the CPUC and the Infrastructure Bank, a limited liability company created by SCE issued approximately $2.5 billion of these notes. For further details, see the discussion in Cash Flows from Financing Activities.
CPUC Restructuring Decision -
The CPUC's December 1995 decision on restructuring California's electric utility industry started the transition to a new market structure, which is expected to provide competition and customer choice and is scheduled to begin March 31, 1998. Key elements of the CPUC's restructuring decision included: creation of the PX and ISO; availability of direct customer access and customer choice; PBR for those utility services not subject to competition; voluntary divestiture of at least 50% of utilities' gas-fueled generation, and implementation of the CTC.
Rate-setting -
In December 1996, SCE filed a more comprehensive plan (elaborating on its July 1996 filing related to the conceptual aspects of separating costs as requested by CPUC and FERC directives) for the functional unbundling of its rates for electric service, beginning January 1, 1998. In response to CPUC and FERC orders, as well as the new restructuring legislation, this filing addressed the implementation-level detail for the functional unbundling of rates into separate charges for energy, transmission, distribution, the CTC, public benefit programs and nuclear decommissioning.
The transmission component of this rate unbundling process was addressed at the FERC through a March 1997 filing. In December 1997, the FERC approved these rates, subject to refund, to be effective on the date the ISO begins operation. CPUC hearings on SCE's rate unbundling (also known as rate-setting) plan were concluded in April 1997. In August 1997, the CPUC issued a decision which adopted the methodology for determining CTC residually (see CTC discussion below) and adopted SCE's revenue requirement components for public benefit programs and nuclear decommissioning. The decision also adjusted SCE's proposed distribution revenue requirement by reallocating $76 million of it annually to other functions such as generation and transmission. Under the decision, SCE will be able to recover most of the reallocated amount through market revenue, other rate-making mechanisms after petitioning the CPUC to modify its prior decisions, or another review process later in its divestiture proceeding.
PX and ISO -
In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas & Electric Company filed a proposal with the FERC regarding the creation of the PX and the ISO. In November 1996, the FERC conditionally accepted the proposal and directed the three utilities, the ISO, and the PX to file more specific information. The filing was made in March 1997, and included SCE's proposed transmission revenue requirement.
On October 29, 1997, the FERC gave conditional, interim authorization for operation of the PX and ISO to begin on January 1, 1998. The FERC stated it would closely monitor the PX and ISO, require further studies and make modifications, where necessary. A comprehensive review will be performed by the FERC after three years of operation of the PX and ISO.
On December 22, 1997, the PX and ISO governing boards announced a delay in the planned start-up of the PX and ISO due to insufficient testing of operational, settlement and billing systems. The PX and ISO are now expected to begin operation by March 31, 1998.
In July 1996, the three utilities jointly filed an application with the CPUC requesting approval to establish a restructuring trust which would obtain loans up to $250 million for the development of the ISO and PX I 8
Southern California Edison Company through January 1, 1998. The loans are backed by utility guarantees; SCE's share was 45%, or $113 million. In August 1996, the CPUC issued an interim order establishing the restructuring trust and the funding level of $250 million, which has been used to build the hardware and software systems for the ISO and PX. The ISO and PX will repay the trust's loans and recover funds from future ISO and PX customers.
In November 1997, the CPUC approved a petition jointly filed by the three utilities which requested an increase in the loan guarantees from $250 million to $300 million; SCE's share of this new total is $135 million. In December 1997, the CPUC approved a remaining item with respect to the petition which requested that the one-time restructuring implementation charge, to be paid to the PX by the utilities, be deemed a non-bypassable charge to be recovered from all retail customers. The amount of the PX charge is $85 million; SCE's share is 45%, or $38 million.
Direct Customer Access -
In May 1997, the CPUC issued a decision describing how all California investor-owned-utility customers will be able to choose who will provide them with electric generation service beginning January 1, 1998. On December 30, 1997, the CPUC issued a decision delaying direct access until March 31, 1998, due to operational delays in the start-up of the PX and ISO. On this date, customers will be able to choose to remain utility customers with bundled electric service from SCE (which will purchase its power through the PX), or choose direct access, which means the customer can contract directly with either independent power producers or retail electric service providers such as power brokers, marketers and aggregators. Additionally, all investor-owned-utility customers must pay the CTC whether or not they choose to buy power through SCE.
Electric utilities will continue to provide the core distribution service of delivering energy through its distribution system regardless of a customer's choice of electricity supplier. The CPUC will continue to regulate the prices and service obligations related to distribution services. If the new competitive market cannot accommodate the volume of direct access transactions, the CPUC could implement a contingency plan. However, the CPUC believes it is likely that interest in and migration to direct access will be gradual.
Revenue Cycle Services -
A decision issued by the CPUC in May 1997, introduces customer choice to metering, billing and related services (referred to as revenue cycle services) that are now provided by California's investor-owned utilities. Under this revenue cycle services unbundling decision, beginning in January 1998, direct access customers may choose to have either SCE or their electric generation service provider render consolidated (energy and distribution) bills, or they may choose to have separate billings from each service provider. However, not all electric generation service providers will necessarily offer each billing option. In addition, beginning in January 1998, customers with maximum demand above 20 kW (primarily industrial and large commercial) can choose SCE or any other supplier to provide their metering service. All other customers will have this option beginning in January 1999. In determining whether any credit should be provided by the utility to firms providing customers with revenue cycle services, and the amount of any such credit, the CPUC has indicated that it is appropriate to net the cost incurred by the utility and the cost avoided by the utility as a result of such services being provided by the other firm rather than by the utility. The unbundling of revenue cycle services will expose SCE to the possible loss of revenue, higher stranded costs and a reduction in revenue security.
PBR -
In 1993, SCE filed for a PBR mechanism to determine most of its revenue (excluding fuel). The filing was subsequently divided between transmission and distribution (T&D) and power generation.
In September 1996, the CPUC adopted a non-generation or T&D PBR mechanism for SCE which began on January 1, 1997. According to the CPUC, beginning in 1998 (coincident with the initiation of the competitive market), the transmission portion is to be separated from non-generation PBR and subject to ratemaking under the rules of the FERC. The distribution-only PBR will extend through December 2001.
Key elements of the non-generation PBR include: T&D rates indexed for inflation based on the Consumer Price Index less a productivity factor; elimination of the kilowatt-hour sales adjustment; 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 T&D operations.
9
Management's Discussion and Analysis of Results of Operations and Financial Condition With the CPUC's 1995 restructuring decision and the passage of restructuring legislation in 1996, the majority of power generation ratemaking (primarily fossil-fueled and nuclear) was assigned to other mechanisms. In April 1997, a CPUC interim order determined that the proposed structure of the fossil fueled plants' must-run contracts were under the FERC's jurisdiction. On October 31, 1997, SCE filed must-run tariff schedules with the FERC covering its six ISO-designated must-run plants.
In the meantime, SCE is pursuing the divestiture of these plants (see Divestiture discussion below) and might not ever itself provide service under these FERC tariff schedules.
In December 1997, the CPUC adopted a PBR-type rate-making mechanism for SCE's hydroelectric plants. The mechanism sets the hydroelectric revenue requirement in 1998 and establishes a formula for extending it through 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 to transition to a competitive market (see CTC discussion below).
Divestiture -
In November 1996, SCE filed an application with the CPUC to voluntarily divest, by auction, all 12 of its oil-and gas-fueled generation plants. This application builds on SCE's March 1996 plan which outlined how SCE proposed to divest 50% of these assets. Under the new proposal, SCE would continue to operate and maintain the divested power plants for at least two years following their sale, as mandated by the restructuring legislation enacted in September 1996. In addition, SCE would offer workforce transition programs to those employees who may be impacted by divestiture-related job reductions. SCE's proposal is contingent on the overall electric industry restructuring implementation process continuing on a satisfactory path. In September 1997, the CPUC approved SCE's proposal to auction the 12 plants.
On December 1, 1997, SCE filed a compliance filing with the CPUC stating that it had sold 10 plants. On December 16, 1997, the CPUC approved the sale of the 10 plants. On February 6, 1998, SCE filed a compliance filing with the CPUC for the sale of an 11th plant. CPUC approval of the sale is expected before March 31, 1998. The total sales price of the 11 plants is $1.1 billion, or 2.16 times their combined book value of $531 million. Net proceeds of the sales will be used to reduce stranded costs, which otherwise were expected to be collected through the CTC mechanism. The transfer of ownership of the 11 plants is expected to occur shortly before the start of the new competitive market, which the PX and ISO expect to occur on March 31, 1998. The sale and CPUC approval of the single remaining plant is expected to be completed in early 1998.
CTC -
Recovery of costs to transition to a competitive market is being implemented 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 20, 1995, decision date. In August 1996, in compliance with the CPUC's restructuring decision, SCE filed its application to estimate its 1998 transition costs. In October 1996, SCE amended its transition cost filing to reflect the effects of the legislation enacted in September 1996.
Under the rate freeze codified in the legislation, the CTC will be determined residually (i.e., after subtracting other cost components for the PX, T&D, nuclear decommissioning and public benefit programs). Nevertheless, the CPUC directed that the amended application provide estimates of SCE's potential transition costs from 1998 through 2030. SCE provided two estimates between approximately
$13.1 billion (1998 net present value) assuming the fossil plants have a market value equal to their net book value, and $13.8 billion (1998 net present value) assuming the fossil plants have no market value.
These estimates are based on incurred costs, forecasts of future costs and assumed market prices.
However, changes in the assumed market prices could materially affect these estimates. The potential transition costs are comprised of: $7.5 billion from SCE's qualifying facility contracts, which are the direct result of prior legislative and regulatory mandates; and $5.6 billion to $6.3 billion from costs pertaining to certain generating plants (successful completion of the sale of SCE's gas-fired generating plants would reduce this estimate of transition costs for SCE-owned generation to less than $5 billion) and regulatory commitments consisting of costs incurred (whose recovery has been deferred by the CPUC) to provide 10
Southern California Edison Company 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 (as discussed in Regulatory Matters), and certain other costs. In February 1997, SCE filed an update to the CTC filing to reflect approval by the CPUC of settlements regarding ratemaking for SCE's share of Palo Verde and the buyout of a power purchase agreement, as well as other minor data updates. No substantive changes in the total CTC estimates were included. This issue has been separated into two phases; Phase 1 addresses the rate-making issues and Phase 2 the quantification issues.
A decision on Phase 1 was issued in June 1997, which, among other things, required the establishment of a transition cost balancing account and annual transition cost proceedings, set a market rate forecast for 1998 transition costs, and required that generation-related regulatory assets be amortized ratably over a 48-month period. Hearings on Phase 2 were held in May and June 1997 and a final decision was issued on November 19, 1997. The Phase 2 decision established the calculation methodologies and procedures for SCE to collect its transition costs from 1998 through the end of the rate freeze. The Phase 2 decision also reduced 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. The decision, excluding the effects of other rate actions, had a negative impact on 1997 earnings of approximately $14 million. SCE has filed an application for rehearing on the 1997 rate of return issue.
Accounting for Generation-Related Assets -
If the CPUC's electric industry restructuring plan is implemented as outlined above, SCE would be allowed to recover its CTC through non-bypassable charges to its distribution customers (although its investment in certain generation assets would be subject to a lower authorized rate of return).
As previously reported, from November 1996 to July 1997, SCE and the other major California electric utilities were engaged in discussions with the Securities and Exchange Commission staff regarding the proper application of regulatory accounting standards in light of the electric industry restructuring legislation enacted by the State of California in September 1996 and the CPUC's electric industry restructuring plan. This issue was placed on the agenda of the Financial Accounting Standards Board's Emerging Issues Task Force (EITF) during April 1997 and a final consensus was reached at the July EITF meeting. During the third quarter of 1997, SCE implemented the EITF consensus and discontinued application of accounting principles for rate-regulated enterprises for its investment in generation facilities.
However, implementation of the EITF consensus did not require SCE to write off any of its generation related assets, including regulatory assets of approximately $600 million at December 31, 1997. SCE has retained these assets on its balance sheet because the legislation and restructuring plan referred to above make probable their recovery through a non-bypassable CTC to distribution customers. These regulatory assets relate primarily to the recovery of accelerated income tax benefits previously flowed through to customers, purchased power contract termination payments, unamortized losses on reacquired debt, and the recovery of amounts deferred under the Palo Verde rate phase-in plan. The consensus reached by the EITF also permits the recording of new generation-related regulatory assets during the transition period that are probable of recovery through the CTC mechanism.
If during the transition period events were to occur that made the recovery of these generation-related regulatory assets no longer probable, SCE would be required to write off the remaining balance of such assets as a one-time, non-cash charge against earnings. If such a write-off were to be required, SCE believes that it should not affect the recovery of stranded costs provided for in the legislation and restructuring plan.
Although depreciation-related differences could result from applying a regulatory prescribed depreciation method (straight-line, remaining-life method) rather than a method that would have been applied absent the regulatory process, SCE believes that the depreciable lives of its generation-related assets would 11
Management's Discussion and Analysis of Results of Operations and Financial Condition not vary significantly from that of an unregulated enterprise, as the CPUC bases depreciable lives on periodic studies that reflect the physical useful lives of the assets.
SCE also believes that any depreciation-related differences would be recovered through the CTC.
If events occur during the restructuring process that result in all or a portion of the CTC being improbable of recovery, SCE could have additional write-offs associated with these costs if they are not 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 implementation phases, or the effect, after the transition period, that competition will have on its results of operations or financial position.
FERC Restructuring Decision In April 1996, the FERC issued its decision on stranded-cost recovery and open access transmission, effective July 1996. The decision, reaffirmed by the FERC in its March and November 1997 orders, requires all electric utilities subject to the FERC's jurisdiction to file transmission tariffs which provide competitors with increased access to transmission facilities for wholesale transactions and also establishes information requirements for the transmission utility. The decision also provides utilities with the opportunity to recover stranded costs associated with existing wholesale customers, retail-turned wholesale customers and retail wheeling when the state regulatory body does not have authority to address retail stranded costs. Even though the CPUC is currently addressing stranded-cost recovery through the CTC proceedings, the FERC has also asserted primary jurisdiction over the recovery of stranded costs associated with retail-turned-wholesale customers, such as a new municipal electric system or a municipal annexation. However, the FERC did clarify that it does not intend to prevent or interfere with a state's authority and that it has discretion to defer to a state stranded-cost-calculation method.
In January 1997, the FERC accepted the open access transmission tariff SCE filed in compliance with the April 1996 decision. The rates included in the tariff are being collected subject to refund. In May 1997, SCE filed a revised open access tariff to reflect the few revisions set forth in the %
March 1997 order. The open access transmission tariff will be terminated on the date the ISO begins operation.
Environmental Protection SCE is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.
As further discussed in Note 10 to the Consolidated Financial Statements, 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. Unless there is a probable amount, SCE records the lower end of this likely range of costs.
In connection with the issuance of the San Onofre Units 2 and 3 operating permits, SCE reached agreement with the California Coastal Commission in 1991 to restore certain marine mitigation sites. The restorations include two sites: designated wetlands and the construction. of an artificial kelp reef off the California coast. After SCE requested certain modifications to the agreement, the Coastal Commission issued a final ruling in April 1997 to reduce the scope of remediations. SCE elected to pay for the costs of marine mitigation in lieu of placing the funds into a trust. Rate recovery of these costs is occurring through the San Onofre incentive pricing plan discussed in Note 1 to the Consolidated Financial Statements.
12
Southern California Edison Company SCE's recorded estimated minimum liability to remediate its 50 identified sites is $178 million, which includes $75 million for the two sites discussed above. One of SCE's sites, a former pole-treating facility, is considered a federal Superfund site and represents 42% of its recorded liability. The ultimate costs to clean up SCE's identified sites may vary from its recorded liability due to numerous uncertainties inherent in the estimation process. SCE believes that, due to these uncertainties, it is reasonably possible that cleanup costs could exceed its recorded liability by up to $246 million. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes.
The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites, representing $91 million of its recorded liability, through an incentive mechanism. 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 $153 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates. This amount includes $60 million of marine mitigation costs remaining to be recovered through the San Onofre incentive pricing plan.
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 1997 were $10 million.
Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range 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 financial position.
There can be no assurance, however, that future developments, including additional information about existing sites or the identification of new sites, will not require material revisions to such estimates.
The 1990 federal Clean Air Act requires power producers to have emissions allowances to emit sulfur dioxide. Power companies receive emissions allowances from the federal government and may bank or sell excess allowances. SCE expects to have excess allowances under Phase II of the Clean Air Act (2000 and later). The act also calls for a study to determine if additional regulations are needed to reduce regional haze in the southwestern U.S. In addition, another study is in progress to determine the specific impact of air contaminant emissions from the Mohave Coal Generating Station on visibility in Grand Canyon National Park. The potential effect of these studies on sulfur dioxide emissions regulations for Mohave is unknown.
SCE's projected capital expenditures to protect the environment are $820 million for the 1998 -
2002 period, mainly for aesthetics treatment, including undergrounding certain transmission and distribution lines.
The possibility that exposure to electric and magnetic fields (EMF) emanating from power lines, household appliances and other electric sources may result in adverse health effects has been the subject of scientific research. After many years of research, scientists have not found that exposure to EMF causes disease in humans. Research on this topic is continuing. However, the CPUC has issued a decision which provides for a rate-recoverable research and public education program conducted by California electric utilities, and authorizes these utilities to take no-cost or low-cost steps to reduce EMF 13
Management's Discussion and Analysis of Results of Operations and Financial Condition in new electric facilities. SCE is unable to predict when or if the scientific community will be able to reach a consensus on any health effects of EMF, or the effect that such a consensus, if reached, could have on future electric operations.
San Onofre Steam Generator Tubes The San Onofre 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. However, during the Unit 2 scheduled refueling and inspection outage, which was completed in Spring 1997, an increased rate of tube degradation was identified, which resulted in the removal of more tubes from service than had been expected. The steam generator design allows for the removal of up to 10% of the tubes before the rating capacity of the unit must be reduced. As a result of the increased degradation, a mid-cycle inspection outage will be conducted in early 1998 for Unit 2.
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. As a result, a mid-cycle inspection outage is planned for early 1998. However, during Unit 2's Spring 1997 inspection outage, similar tube supports showed no sign of such erosion.
Proposed New Accounting Standard During 1996, the Financial Accounting Standards Board issued an exposure draft that would establish accounting standards for the recognition and measurement of closure and removal obligations.
The exposure draft would require the estimated present value of an obligation to be recorded as a liability, along with a corresponding increase in the plant or regulatory asset accounts when the obligation is incurred. If the exposure draft is approved in its present form, it would affect SCE's accounting practices for the decommissioning of its nuclear power plants, obligations for coal mine reclamation costs and any other activities related to the closure or removal of long-lived assets. SCE does not expect that the %
accounting changes proposed in the exposure draft would have an adverse effect on its results of operations even after deregulation due to its current and expected future ability to recover these costs through customer rates.
Year 2000 Issue Many of SCE's existing computer systems identify a year by using only two digits instead of four. If not corrected, these programs could fail or create erroneous results when the new century begins. This situation has been referred to generally as the Year 2000 Issue.
SCE has developed plans and is addressing the programming changes that it has determined are necessary in order for its computer systems to function properly beginning in 2000. 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, 1999.
Preliminary estimates of the costs to complete these modifications, including the cost of new hardware and software application modifications, range from $55 million to $80 million, about half of which are expected to be capital costs. Current rate levels for providing electric service should be sufficient to provide funding for these modifications. Remediation of existing critical systems is expected to be 75% complete by the end of 1998. 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.
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.
14
Consolidated Statements of Income Southern California Edison Company in thousands Year ended December 31, 1997 1996 1995 Operating revenue
$7,953,386
$7,583,382
$7,872,718 Fuel 881,471 630,512 614,954 Purchased power 2,854,002 2,705,880 2,581,878 Provisions for regulatory adjustment clauses -
net (410,935)
(225,908) 229,744 Other operating expenses 1,212,468 1,178,316 1,226,534 Maintenance 405,545 329,371 356,693 Depreciation and decommissioning 1,239,878 1,063,505 954,141 Income taxes 582,031 578,329 559,694 Property and other taxes 129,038 190,284 200,236 Total operating expenses 6,893,498 6,450,289 6,723,874 Operating income 1,059,888 1,133,093 1,148,844 Provision for rate phase-in plan (48,486)
(84,288)
(122,233)
Allowance for equity funds used during construction 7,651 15,579 19,082 Interest and dividend income 44,636 37,855 37,644 Other nonoperating income (deductions) -
net (23,036)
(3,623) 45,651 Total other income (deductions) -
net (19,235)
(34,477)
(19,856)
Income before interest expense 1,040,653 1,098,616 1,128,988 Interest on long-term debt 345,592 380,812 385,187 Other interest expense 101,078 73,914 80,130 Allowance for borrowed funds used during construction (9,213)
(9,794)
(14,489)
Capitalized interest (2,398)
(1,711)
(1,531)
Total interest expense -
net 435,059 443,221 449,297 Net income 605,594 655,395 679,691 Dividends on preferred stock 29,488 34,395 36,764 Earnings available for common stock
$ 576,106
$ 621,000
$ 642,927 Consolidated Statements of Retained Earnings In thousands Year ended December 31, 1997 1996 1995 Balance at beginning of year
$2,665,612
$2,780,058
$2,683,568 Net income 605,594 655,395 679,691 Dividends declared on common stock (1,829,040)
(735,429)
(545,672)
Dividends declared on preferred stock (29,488)
(34,395)
(36,764)
Reacquired capital stock expense (4,8)
(17)
(765)
Balance at end of year
$1,407,834
$2,665,612
$2,780,058 The accompanying notes are integral part of these financial statements.
15
Consolidated Balance Sheets In thousands December 31, 1997 1996 ASSETS Transmission and distribution:
Utility plant, at original cost, subject to cost-based rate regulation
$11,213,352
$10,973,311 Accumulated provision for depreciation (5,573,742)
(5,128,652)
Construction work in progress 492,614 461,048 6,132,224 6,305,707 Generation:
Utility plant, at original cost, not subject to cost-based rate regulation 9,522,127 9,427,076 Accumulated provision for depreciation and decommissioning (4,970,137)
(4,302,419)
Construction work in progress 100,283 95,597 Nuclear fuel, at amortized cost 154,757 176,827 4,807,030 5,397,081 Total utility plant 10,939,254 11,702,788 Nonutility property -
less accumulated provision for depreciation of $24,730 and $25,102 at respective dates 67,869 63,931 Nuclear decommissioning trusts 1,831,460 1,485,525 Other investments 171,399 103,973 Total other property and investments 2,070,728 1,653,429 Cash and equivalents 962,272 319,942 Receivables, including unbilled revenue, less allowances of $26,453 and $26,079 for uncollectible accounts at respective dates 906,388 921,083 Fuel inventory 58,059 72,480 Materials and supplies, at average cost 132,980 154,266 Accumulated deferred income taxes -
net 123,146 240,429 Regulatory balancing accounts -
net 193,311 Prepayments and other current assets 93,098 105,137 Total current assets 2,469,254 1,813,337 Unamortized debt issuance and reacquisition expense 359,304 346,834 Rate phase-in plan 3,777 50,703 Income tax-related deferred charges 1,543,380 1,741,091 Other deferred charges 673,601 428,370 Total deferred charges 2,580,062 2,566,998 Total assets
$18,059,298
$17,736,552 The accompanying notes are an integral part of these financial statements.
16
Southern California Edison Company In thousands, except share amounts December 31, 1997 1996 CAPITALIZATION AND LIABILITIES Common shareholder's equity:
Common stock (434,888,104 shares outstanding at each date)
$ 2,168,054 2,168,054 Additional paid-in capital and other 382,054 210,857 Retained earnings 1,407,834 2,665,612 3,957,942 5,044,523 Preferred stock:
Not subject to mandatory redemption 183,755 283,755 Subject to mandatory redemption 275,000 275,000 Long-term debt 6,144,597 4,778,703 Total capitalization 10,561,294 10,381,981 Other long-term liabilities 479,637 423,925 Current portion of long-term debt 692,875 501,470 Short-term debt 322,028 230,149 Accounts payable 406,704 392,779 Accrued taxes 509,270 484,688 Accrued interest 85,406 93,363 Dividends payable 95,146 108,563 Regulatory balancing accounts -
net 181,488 Deferred unbilled revenue and other current liabilities 931,856 825,317 Total current liabilities 3,043,285 2,817,817 Accumulated deferred income taxes -
net 2,939,471 3,170,696 Accumulated deferred investment tax credits 326,728 347,118 Customer advances and other deferred credits 708,745 595,015 Total deferred credits 3,974,944 4,112,829 Minority Interest 138 Commitments and contingencies (Notes 2, 8, 9 and 10)
Total capitalization and liabilities
$18,059,298
$ 17,736,552 The accompanying notes are an integral part of these financial statements.
17
Consolidated Statements of Cash Flows Southern California Edison Company In thousands Year ended December 31, 1997 1996 1995 Cash flows from operating activities:
Net income
$ 605,594
$ 655,395 679,691 Adjustments for non-cash items:
Depreciation and decommissioning 1,239,878 1,063,505 954,141 Amortization 81,363 90,931 68,064 Rate phase-in plan 46,926 79,011 111,016 Deferred income taxes and investment tax credits 63,379 46,122 (208,671)
Other long-term liabilities 55,712 79,733 33,129 Other -
net (208,624)
(153,034)
(261)
Changes in working capital:
Receivables 14,695 (9,120)
(9,873)
Regulatory balancing accounts (374,799)
(156,379) 282,157 Fuel inventory, materials and supplies 35,707 38,791 (19,499)
Prepayments and other current assets 12,039 9,152 (15,511)
Accrued interest and taxes 16,625 (58,827) 34,704 Accounts payable and other current liabilities 120,464 93,362 45,355 Net cash provided by operating activities 1,708,959 1,778,642 1,954,442 Cash flows from financing activities:
Long-term debt issued 396,309 393,829 Long-term debt repaid (916,145)
(403,957)
(422,503)
Rate reduction notes issued 2,449,289 Preferred stock redeemed (100,000)
(75,000)
Nuclear fuel financing -
net (20,140) 41,803 31,134 Short-term debt financing -
net 91,879 (129,359)
(316,006)
Capital transferred 153,000 Dividends paid (1,871,944)
(799,593)
(559,886)
Net cash used by financing activities (214,061)
(894,797)
(948,432)
Cash flows from investing activities:
Additions to property and plant (685,320)
(616,427)
(772,950)
Funding of nuclear decommissioning trusts (153,756)
(148,158)
(150,595)
Unrealized gain in equity investments -
net 32,911 14,900 8,483 Other -
net (46,403)
(75,985)
(21,273)
Net cash used by investing activities (852,568)
(825,670)
(936,335)
Net increase in cash and equivalents 642,330 58,175 69,675 Cash and equivalents, beginning of year 319,942 261,767 192,092 Cash and equivalents, end of year
$ 962,272
$ 319,942
$ 261,767 Cash payments for interest and taxes:
Interest -
net of amounts capitalized
$ 342,137
$ 346,980
$ 381,267 Taxes 438,003 545,834 692,780 The accompanying notes are an integral part of these financial statements.
18
Notes to Consolidated Financial Statements Southern California Edison Company Note 1.
Summary of Significant Accounting Policies Accounting Principles Southern California Edison Company's (SCE) accounting policies conform with generally accepted accounting principles (GAAP), including the accounting principles for rate-regulated enterprises which reflect the rate-making policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). As a result of industry restructuring legislation enacted by the State of California and a related change in the application of accounting principles for rate-regulated enterprises adopted recently by the Financial Accounting Standards Board's Emerging Issues Task Force (EITF), during the third quarter of 1997, SCE began accounting for its investment in generation facilities in accordance with GAAP applicable to enterprises in general. Although this change did not result in any adjustment of the carrying value of such investment, it is shown separately on SCE's Balance Sheet under the caption: Generation utility plant, at original cost, not subject to cost-based rate regulation. The competitive market for electric generation in California is scheduled to begin March 31, 1998.
Competition Transition Charge (CTC)
Beginning January 1, 1998, a non-bypassable charge is being billed to all customers, which provides SCE the opportunity to recover its costs to transition to a competitive market.
Consolidation Policy The consolidated financial statements include SCE and its subsidiaries. Intercompany transactions have been eliminated.
Estimates Financial statements prepared in compliance with GAAP require management to make estimates and assumptions that affect the amounts reported in the financial statements and disclosure of contingencies.
Actual results could differ from those estimates. Certain significant estimates related to electric utility restructuring, decommissioning and contingencies are further discussed in Notes 2, 9 and 10 to the Consolidated Financial Statements, respectively.
Fuel Inventory Fuel inventory is valued under the last-in, first-out method for fuel oil and natural gas, and under the first in, first-out method for coal.
Nature of Operations SCE's outstanding common stock is owned entirely by its parent company, Edison International. SCE is a public utility which produces and supplies electric energy for its 4.3 million customers in Central and Southern California.
SCE currently operates in a highly regulated environment in which it has an obligation to deliver electric service to customers in return for an exclusive franchise within its service territory. This regulatory environment is changing, as further discussed in Note 2 to the Consolidated Financial Statements.
Nuclear The CPUC authorized rate phase-in plans to defer the collection of $200 million in revenue for each unit at the Palo Verde Nuclear Generating Station during the first four years of operation and recover the deferred revenue (including interest) evenly over the following six years. The phase-in plans ended in February 1996, September 1996 and January 1998 for Units 1, 2 and 3, respectively.
19
Notes to Consolidated Financial Statements Under federal law, SCE is liable for its share of the estimated costs to decommission three federal nuclear enrichment facilities (based on purchases). These costs, which will be paid over 15 years, are recorded as a fuel cost and recovered through non-bypassable customer rates.
In 1992, SCE discontinued operation of San Onofre Nuclear Generating Station Unit 1, after the CPUC approved a settlement agreement between SCE and the CPUC's Office of Ratepayer Advocates (ORA) to discontinue operation of Unit 1 because operation of the unit was no longer cost-effective. As part of the agreement, SCE recovered its remaining investment over a four-year period ending August 1996, earning an 8.98% rate of return.
In 1994, the CPUC authorized accelerated recovery of SCE's nuclear plant investments by $75 million per year, with a corresponding deceleration in recovery of its transmission and distribution assets through revised depreciation estimates over their remaining useful lives.
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, earning a 7.35% fixed rate of return. Operating costs, including nuclear fuel and nuclear fuel financing costs, and incremental capital expenditures at San Onofre Units 2 and 3 are recovered through an incentive pricing plan which allows SCE to receive about 40 per kilowatt-hour through 2003. Any differences between these costs and the incentive price will flow through to the shareholders. Beginning January 1, 1998, the accelerated plant recovery and the incentive pricing plan became part of the CTC mechanism. Beginning in 2004, SCE will be required to share equally with ratepayers the net benefits received from operation of the units.
In January 1997, the CPUC authorized a further acceleration of the recovery of its remaining investment of $1.2 billion in Palo Verde Units 1, 2 and 3. The accelerated recovery will continue through December 2001, earning a 7.35% fixed rate of return. The accelerated plant recovery, as well as operating costs, including nuclear fuel and nuclear fuel financing costs, and incremental capital expenditures, are subject to balancing account treatment through 2001. Beginning January 1, 1998, the balancing account became part of the CTC 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 equally with ratepayers the net benefits received from operation of Palo Verde.
Reclassifications Certain prior-year amounts were reclassified to conform to the December 31, 1997, financial statement presentation.
Regulatory Balancing Accounts Prior to January 1, 1998, the differences between CPUC-authorized and actual base-rate revenue from kilowatt-hour sales and CPUC-authorized and actual energy costs were accumulated in balancing accounts until they were refunded to, or recovered from, utility customers through authorized rate adjustments (with interest).
Beginning January 1, 1998, the difference between generation related revenue and generation-related costs is being accumulated in a transition cost balancing account. These transition costs are being recovered from utility customers (with interest) through the CTC through 2001.
Income tax effects on all balancing account changes are deferred.
In January 1997, in compliance with the new restructuring legislation, overcollections in the kilowatt-hour sales and energy cost balancing accounts at December 31, 1996, were transferred to an interim balancing account and were credited to the transition cost balancing account beginning in January 1998.
20
Southern California Edison Company Research, Development and Demonstration (RD&D)
SCE capitalizes RD&D costs that are expected to result in plant construction. If construction does not occur, these costs are charged to expense. RD&D expenses are recorded in a balancing account and, at the end of the rate-case cycle, any authorized but unspent RD&D funds are refunded to customers.
RD&D expenses were $39 million in 1997, $21 million in 1996 and $28 million in 1995.
Revenue Operating revenue includes amounts for services rendered but unbilled at the end of each year.
Utility Plant Plant additions, including replacements and betterments, are capitalized. Such costs include direct material and labor, construction overhead and an allowance for funds used during construction (AFUDC).
AFUDC represents the estimated cost of debt and equity funds that finance utility-plant construction.
AFUDC is capitalized during plant construction and reported in current earnings.
AFUDC is recovered in rates through depreciation expense over the useful life of the related asset. Depreciation of utility plant is computed on a straight-line, remaining-life basis.
Replaced or retired property and removal costs less salvage are charged to the accumulated provision for depreciation. Depreciation expense stated as a percent of average original cost of depreciable utility plant was 5.2% for 1997, 4.2% for 1996 and 3.6% for 1995.
During the third quarter of 1997, SCE discontinued accounting for its investment in generation facilities using accounting principles applicable to rate-regulated enterprises and began accounting for such investment using GAAP applicable to enterprises in general. The carrying value of such investment was unaffected by this change.
Note 2. Regulatory Matters California Electric Utility Industry Restructuring Restructuring Legislation -
In September 1996, the State of California enacted legislation to provide a transition to a competitive market structure. The legislation substantially adopted the CPUC's December 1995 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.
Transition costs related to power-purchase contracts would be recovered through the terms of their contracts while most of the remaining transition costs would be recovered through 2001. The legislation also included provisions to finance a portion of the stranded costs that residential and small commercial customers would have paid between 1998 and 2001, which would allow SCE to reduce rates by at least 10% to these customers, beginning January 1, 1998. The financing would occur with securities issued by the California Infrastructure and Economic Development Bank, or an entity approved by the Bank. The legislation included a rate freeze for all other customers, including large commercial and industrial customers, as well as provisions for continued funding for energy conservation, low-income programs and renewable resources.
Despite the rate freeze, SCE expects to be able to recover its revenue requirement during the 1998 -
2001 transition period.
In addition, the legislation mandated the implementation of the CTC that provides utilities the opportunity to recover costs made uneconomic by electric utility restructuring. Finally, the legislation 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.
21
Notes to Consolidated Financial Statements Rate Reduction Notes -
In May 1997, SCE filed an application with the CPUC requesting approval of the issuance of an aggregate amount of up to $3 billion of rate reduction notes in one or more series or classes and a 10% rate reduction for the period from January 1, 1998, through March 31, 2002. At the same time, SCE filed an application with the California Infrastructure and Economic Development Bank for approval to issue the notes. Residential and small commercial customers will repay the notes over the expected 10-year term through non-bypassable charges based on electricity consumption. In December 1997, after receiving approval from both the CPUC and the Infrastructure Bank, a limited liability company created by SCE issued approximately $2.5 billion of these notes. For further details, see the discussion under Long-Term Debt in Note 3 to the Consolidated Financial Statements.
CPUC Restructuring Decision -
The CPUC's December 1995 decision on restructuring California's electric utility industry started the transition to a new market structure, which is expected to provide competition and customer choice and is scheduled to begin March 31, 1998.
Key elements of the CPUC's restructuring decision included:
creation of an independent power. exchange (PX) and independent system operator (ISO); availability of direct customer access and customer choice; 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 CTC.
Rate-setting -
In December 1996, SCE filed a more comprehensive plan (elaborating on its July 1996 filing related to the conceptual aspects of separating costs as requested by CPUC and FERC directives) for the functional unbundling of its rates for electric service, beginning January 1, 1998. In response to CPUC and FERC orders, as well as the new restructuring legislation, this filing addressed the implementation-level detail for the functional unbundling of rates into separate charges for energy, transmission, distribution, the CTC, public benefit programs and nuclear decommissioning.
The transmission component of this rate unbundling process was addressed at the FERC through a March 1997 filing. In December 1997, the FERC approved these rates, subject to refund, to be effective on the date the ISO begins operation. CPUC hearings on SCE's rate unbundling (also known as rate-setting) plan were concluded in April 1997. In August 1997, the CPUC issued a decision which adopted the methodology for determining CTC residually (see CTC discussion below) and adopted SCE's revenue requirement components for public benefit programs and nuclear decommissioning. The decision also adjusted SCE's proposed distribution revenue requirement by reallocating $76 million of the amount annually to other functions such as generation and transmission. Under the decision, SCE will be able to recover most of the reallocated amount through market revenue, other rate-making mechanisms after petitioning the CPUC to modify its prior decisions, or another review process later in its divestiture proceeding.
PX and ISO -
In April 1996, SCE, Pacific Gas & Electric Company and San Diego Gas & Electric Company filed a proposal with the FERC regarding the creation of the PX and the ISO. In November 1996, the FERC conditionally accepted the proposal and directed the three utilities, the ISO, and the PX to file more specific information. The filing was made in March 1997, and included SCE's proposed transmission revenue requirement.
On October 29, 1997, the FERC gave conditional, interim authorization for operation of the PX and ISO to begin on January 1, 1998. The FERC stated it would closely monitor the PX and ISO, require further studies and make modifications, where necessary. A comprehensive review will be performed by the FERC after three years of operation of the PX and ISO.
On December 22, 1997, the PX and ISO governing boards announced a delay in the planned start-up of the PX and ISO due to insufficient testing of operational, settlement and billing systems. The PX and ISO are now expected to begin operation by March 31, 1998.
In July 1996, the three utilities jointly filed an application with the CPUC requesting approval to establish a restructuring trust which would obtain loans up to $250 million for the development of the ISO and PX through January 1, 1998. The loans are backed by utility guarantees; SCE's share was 45%, or $113 million. In August 1996, the CPUC issued an interim order establishing the restructuring trust and the funding level of $250 million, which has been used to build the hardware and software systems for the 22
Southern California Edison Company ISO and PX. The ISO and PX will repay the trust's loans and recover funds from future ISO and PX customers. In November 1997, the CPUC approved a petition jointly filed by the three utilities which requested an increase in the loan guarantees from $250 million to $300 million; SCE's share of this new total is $135 million. In December 1997, the CPUC approved a remaining item with respect to the petition which requested that the one-time restructuring implementation charge, to be paid to the PX by the utilities, be deemed a non-bypassable charge to be recovered from all retail customers. The amount of the PX charge is $85 million; SCE's share is 45%, or $38 million.
Direct Customer Access -
In May 1997, the CPUC issued a decision describing how all California investor-owned-utility customers will be able to choose who will provide them with electric generation service beginning January 1, 1998. On December 30, 1997, the CPUC issued a decision delaying direct access until March 31, 1998, due to the operational delays in the start-up of the PX and ISO. On this date, customers will be able to choose to remain utility customers with bundled electric service from SCE (which will purchase its power through the PX), or choose direct access, which means the customer can contract directly with either independent power producers or retail electric service providers such as power brokers, marketers and aggregators. Additionally, all investor-owned-utility customers must pay the CTC whether or not they choose to buy power through SCE. Electric utilities will continue to provide the core distribution service of delivering energy through its distribution system regardless of a customer's choice of electricity supplier. The CPUC will continue to regulate the prices and service obligations related to distribution services. If the new competitive market cannot accommodate the volume of direct access transactions, the CPUC could implement a contingency plan. However, the CPUC believes it is likely that interest in and migration to direct access will be gradual.
Revenue Cycle Services - A decision issued by the CPUC in May 1997, introduces customer choice to metering, billing and related services (referred to as revenue cycle services) that are now provided by California's investor-owned utilities. Under this revenue cycle services unbundling decision, beginning in January 1998, direct access customers may choose to have either SCE or their electric generation service provider render consolidated (energy and distribution) bills, or they may choose to have separate billings from each service provider. However, not all electric generation service providers will necessarily offer each billing option. In addition, beginning in January 1998, customers with maximum demand above 20 kW (primarily industrial and large commercial) can choose SCE or any other supplier to provide their metering service. All other customers will have this option beginning in January 1999. In determining whether any credit should be provided by the utility to firms providing customers with revenue cycle services, and the amount of any such credit, the CPUC has indicated that it is appropriate to net the cost incurred by the utility and the cost avoided by the utility as a result of such services being provided by the other firm rather than by the utility.
PBR - In 1993, SCE filed for a PBR mechanism to determine most of its revenue (excluding fuel). The filing was subsequently divided between transmission and distribution (T&D) and power generation. In September 1996, the CPUC adopted a non-generation or T&D PBR mechanism for SCE which began on January 1, 1997.
According to the CPUC, beginning in 1998 (coincident with the initiation of the competitive market), the transmission portion is to be separated from non-generation PBR and subject to ratemaking under the rules of the FERC. The distribution-only PBR will extend through December 2001.
Key elements of the non-generation PBR include: T&D rates indexed for inflation based on the Consumer Price Index less a productivity factor; elimination of the kilowatt-hour sales adjustment; 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 T&D operations.
With the CPUC's 1995 restructuring decision and the passage of restructuring legislation in 1996, the majority of power generation ratemaking (primarily fossil-fueled and nuclear) was assigned to other mechanisms. In April 1997, a CPUC interim order determined that the proposed structure of the fossil fueled plants' must-run contracts were under the FERC's jurisdiction. On October 31, 1997, SCE filed 23
Notes to Consolidated Financial Statements must-run tariff schedules with the FERC covering its six ISO-designated must-run plants.
In the meantime, SCE is pursuing the divestiture of these plants (see Divestiture discussion below) and might not ever itself provide service under these FERC tariff schedules.
In December 1997, the CPUC adopted a PBR-type rate-making mechanism for SCE's hydroelectric plants. The mechanism sets the hydroelectric revenue requirement in 1998 and establishes a formula for extending it through 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 to transition to a competitive market (see CTC discussion below).
Divestiture -
In November 1996, SCE filed an application with the CPUC to voluntarily divest, by auction, all 12 of its oil-and gas-fueled generation plants. This application builds on SCE's March 1996 plan which outlined how SCEI proposed to divest 50% of these assets. Under the new proposal, SCE would continue to operate and maintain the divested power plants for at least two years following their sale, as mandated by the restructuring legislation enacted in September 1996. In addition, SCE would offer workforce transition programs to those employees who may be impacted by divestiture-related job reductions. SCE's proposal is contingent on the overall electric industry restructuring implementation process continuing on a satisfactory path. In September 1997, the CPUC approved SCE's proposal to auction the 12 plants.
On December 1, 1997, SCE filed a compliance filing with the CPUC stating that it had sold 10 plants. On December 16, 1997, the CPUC approved the sale of the 10 plants. On February 6, 1998, SCE filed a compliance filing with the CPUC for the sale of an 11th plant. CPUC approval of the sale is expected before March 31, 1998. The total sales price of the 11 plants is $1.1 billion, or 2.16 times their combined book value of $531 million. Net proceeds of the sales will be used to reduce stranded costs which otherwise were expected to be collected through a non-bypassable CTC. The transfer of ownership of the 11 plants is expected to occur shortly before the start of the new competitive market, which the PX and ISO currently expect to occur on March 31, 1998.
The sale and CPUC approval of the single remaining plant is expected to be completed in early 1998.
CTC -
The CTC applies to all customers who were using or began using utility services on or after the CPUC's December 20, 1995, decision date. In August 1996, in compliance with the CPUC's restructuring decision, SCE filed its application to estimate its 1998 transition costs. In October 1996, SCE amended its transition cost filing to reflect the effects of the legislation enacted in September 1996. Under the rate freeze codified in the legislation, the CTC will be determined residually (i.e., after subtracting other cost components for the PX, T&D, nuclear decommissioning and public benefit programs). Nevertheless, the CPUC directed that the amended application provide estimates of SCE's potential transition costs from 1998 through 2030. SCE provided two estimates between approximately $13.1 billion (1998 net present value) assuming the fossil plants have a market value equal to their net book value, and $13.8 billion (1998 net present value) assuming the fossil plants have no market value. These estimates are based on incurred costs, forecasts of future costs and assumed market prices. However, changes in the assumed market prices could materially affect these estimates. The potential transition costs are comprised of:
$7.5 billion from SCE's qualifying facilities (QF) contracts, which are the direct result of prior legislative and regulatory mandates; and $5.6 billion to $6.3 billion from costs pertaining to certain generating plants (successful completion of the sale of SCE's gas-fired generating plants would reduce this estimate of transition costs for SCE-owned generation to less than $5 billion) and regulatory commitments consisting of costs incurred (whose recovery has been deferred by the CPUC) to provide 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, (as discussed in Note 1 to the Consolidated Financial Statements) and certain other costs. In February 1997, SCE filed an update to the CTC filing to reflect approval by the CPUC of settlements regarding ratemaking for SCE's share of Palo Verde and the buyout of a power purchase agreement, as well as other minor data updates. No substantive changes in the total CTC estimates were included.
24
Southern California Edison Company This issue has been separated into two phases: Phase 1 addresses the rate-making issues and Phase 2 the quantification issues.
A decision on Phase 1 was issued in June 1997, which, among other things, required the establishment of a transition cost balancing account and annual transition cost proceedings, set a market rate forecast for 1998 transition costs, and required that generation-related regulatory assets be amortized ratably over a 48-month period. Hearings on Phase 2 were held in May and June 1997 and a final decision was issued on November 19, 1997. The Phase 2 decision established the calculation methodologies and procedures for SCE to collect its transition costs from 1998 through the end of the rate freeze. The Phase 2 decision also reduced 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. The decision, excluding the effects of other rate actions, had a negative impact on 1997 earnings of approximately $14 million. SCE has filed an application for rehearing on the 1997 rate of return issue.
Accounting for Generation-Related Assets -
If the CPUC's electric industry restructuring plan is implemented as outlined above, SCE would be allowed to recover its CTC through non-bypassable charges to its distribution customers (although its investment in certain generation assets would be subject to a lower authorized rate of return).
As previously reported, from November 1996 to July 1997, SCE and the other major California electric utilities were engaged in discussions with the Securities and Exchange Commission staff regarding the proper application of regulatory accounting standards in light of the electric industry restructuring legislation enacted by the State of California in September 1996 and the CPUC's electric industry restructuring plan. This issue was placed on the agenda of the EITF during April 1997 and a final consensus was reached at the July EITF meeting. During the third quarter of 1997, SCE implemented the EITF consensus and discontinued application of accounting principles for rate-regulated enterprises for its investment in generation facilities.
However, implementation of the EITF consensus did not require SCE to write off any of its generation related assets, including regulatory assets of approximately $600 million at December 31, 1997. SCE has retained these assets on its balance sheet because the legislation and restructuring plan referred to above make probable their recovery through a CTC to distribution customers. These regulatory assets relate primarily to the recovery of accelerated income tax benefits previously flowed through to customers, purchased power contract termination payments, unamortized losses on reacquired debt, and the recovery of amounts deferred under the Palo Verde rate phase-in plan. The consensus reached by the EITF also permits the recording of new generation-related regulatory assets during the transition period that are probable of recovery through the CTC mechanism.
If during the transition period events were to occur that made the recovery of these generation-related regulatory assets no longer probable, SCE would be required to write off the remaining balance of such assets as a one-time, non-cash charge against earnings. If such a write-off were to be required, SCE believes that it should not affect the recovery of stranded costs provided for in the legislation and restructuring plan.
Although depreciation-related differences could result from applying a regulatory prescribed depreciation method (straight-line, remaining-life method) rather than a method that would have been applied absent the regulatory process, SCE believes that the depreciable lives of its generation-related assets would not vary significantly from that of an unregulated enterprise, as the CPUC bases depreciable lives on periodic studies that reflect the physical useful lives of the assets. SCE also believes that any depreciation related differences would be recovered through the CTC.
25
Notes to Consolidated Financial Statements If events occur during the restructuring process that result in all or a portion of the CTC being improbable of recovery, SCE could have additional write-offs associated with these costs if they are not 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 implementation phases, or the effect, after the transition period, that competition will have on its results of operations or financial position.
FERC Restructuring Decision In April 1996, the FERC issued its decision on stranded-cost recovery and open access transmission, effective July 1996. The decision, reaffirmed by the FERC in its March and November 1997 orders, requires all electric utilities subject to the FERC's jurisdiction to file transmission tariffs which provide competitors with increased access to transmission facilities for wholesale transactions and also establishes information requirements for the transmission utility. The decision also provides utilities with the opportunity to recover stranded costs associated with existing wholesale customers, retail-turned wholesale customers and retail wheeling when the state regulatory body does not have authority to address retail stranded costs. Even though the CPUC is currently addressing stranded-cost recovery through the CTC proceedings, the FERC has also asserted primary jurisdiction over the recovery of stranded costs associated with retail-turned-wholesale customers, such as a new municipal electric system or a municipal annexation. However, the FERC did clarify that it does not intend to prevent or interfere with a state's authority and that it has discretion to defer to a state stranded-cost-calculation method.
In January 1997, the FERC accepted the open access transmission tariff SCE filed in compliance with the April 1996 decision. The rates included in the tariff are being collected subject to refund. In May 1997, SCE filed a revised open access tariff to reflect the few revisions set forth in the March 1997 order. The open access transmission tariff will be terminated on the date the ISO begins operation.
Canadian Gas Contracts In 1994, SCE filed its testimony in the non-QF phase of the 1994 Energy Cost Adjustment Clause proceeding. In 1995, the ORA filed its report on the reasonableness of SCE's gas supply costs for both the 1993 and 1994 record periods. The report recommended a disallowance of $13 million for excessive costs incurred from November 1993 through March 1994 associated with SCE's Canadian gas purchase and supply contracts. The report requested that the CPUC defer finding SCE's Canadian supply and transportation agreements reasonable for the duration of their terms and that the costs under these contracts be reviewed on a yearly basis. In 1996, the ORA issued its report for the 1995 record period recommending a $38 million disallowance for excessive costs incurred from April 1994 through March 1995.
Both proposed disallowances were later consolidated into one proceeding. On December 3, 1997, the CPUC approved a settlement agreement between SCE and the ORA on this and any future issues which will result in a $61 million (including interest) refund to SCE's customers. This refund is fully reflected in the financial statements and will be made in first quarter 1998.
Mojave Cogeneration Contract In 1991, SCE filed its testimony in the QF phase of the 1991 Energy Cost Adjustment Clause proceeding.
In 1993, the ORA filed its report on the reasonableness of SCE's QF contracts and alleged that SCE had imprudently renegotiated a QF contract with the Mojave Cogeneration Company.
The report recommended a disallowance of $32 million (1993 net present value) over the contract's 20-year life.
Subsequently, SCE and the ORA reached a settlement where SCE agreed to a one-time reduction to its energy-cost adjustment clause balancing account of $14 million plus interest.
In October 1996, the CPUC approved the settlement agreement, subject to SCE and the ORA accepting certain conditions concerning the way the $14 million payment would be reflected in rates. After reviewing the decision, SCE declined to accept the condition proposed by the CPUC and in November 1996 filed an application 26
Southern California Edison Company for rehearing. In February 1997, the CPUC denied SCE's application. Because SCE and the ORA were unable to finalize their settlement, hearings on the ORA's disallowance recommendations were held in June 1997. During the hearings, the ORA presented testimony to update its assessment of ratepayer harm, which it now estimates to be $45 million (1997 net present value) over the contract's life. In November 1997, a CPUC administrative law judge (ALJ) issued a proposed decision which would adopt the ORA's $45 million disallowance. In January 1998, the CPUC withdrew the ALJ's proposed decision pending oral arguments. Oral arguments were heard on February 4, 1998, at which time SCE requested an alternate proposed decision be issued. SCE expects this matter to be returned to the CPUC's agenda in the near future and a final decision to be issued during second quarter 1998. SCE cannot predict the final outcome of this matter but does not believe it will materially affect its results of operations.
Note 3. Financial Instruments Cash Equivalents Cash and equivalents include tax-exempt investments ($936 million at December 31, 1997, and
$261 million at December 31, 1996), and time deposits and other investments ($26 million at December 31, 1997, and $59 million at December 31, 1996) with maturities of three months or less.
Derivative Financial Instruments SCE's risk management policy allows the use of derivative financial instruments to manage financial exposure on its investments and fluctuations in interest rates, but prohibits the use of these instruments for speculative or trading purposes.
SCE uses the hedge accounting method to record its derivative financial instruments, except for gas call options. Hedge accounting requires an assessment that the transaction reduces risk, that the derivative be designated as a hedge at the inception of the derivative contract, and that the changes in the market value of a hedge move in an inverse direction to the item being hedged. Under hedge accounting, the derivative itself is not recorded on SCE's balance sheet. Mark-to-market accounting would be used if the hedge accounting criteria were not met.
Interest rate differentials and amortization of premiums for interest rate caps are recorded as adjustments to interest expense. If the derivatives were terminated before the maturity of the corresponding debt issuance, the realized gain or loss on the transaction would be amortized over the remaining term of the debt.
SCE uses the mark-to-market accounting method for its gas call options. Gains and losses from monthly changes in market prices are recorded as income or expense. However, the costs of the options and the market price changes are recovered through the transition cost balancing account. As a result, the mark-to-market gains or losses have no effect on earnings.
Interest rate swaps and caps are used to reduce the potential impact of interest rate fluctuations on floating-rate long-term debt. At the balance sheet date of December 31, 1996, SCE had an interest rate cap agreement which capped the interest rate at 6% for $30 million of debt due 2027; it expired July 1, 1997. At the balance sheet dates of December 31, 1997, and December 31, 1996, SCE had an interest rate swap agreement which fixed the interest rate at 5.585% for $196 million of debt due 2008; it expires February 28, 2008. The interest rate swap agreement requires the parties to pledge collateral according to bond rating and market interest rate changes. At December 31, 1997, SCE had pledged
$19 million as collateral due to a decline in market interest rates. SCE is exposed to credit loss in the event of nonperformance by the counterparty to the agreement, but does not expect the counterparty to fail to meet its obligations.
At December 31, 1997, SCE had gas call options valued at $34 million. These options mitigate SCE's exposure to increases in natural gas prices. Increases in natural gas prices tend to increase the price of electricity purchased from the PX. The options cover various periods from 1998 through 2001.
27
Notes to Consolidated Financial Statements Fair Value of Financial Instruments Fair values of financial instruments were:
In millions December 31, 1997 1996 Cost Fair Cost Fair Instrument Basis Value Basis Value Financial assets:
Decommissioning trusts
$1,371
$1,831
$1,217
$1,486 Equity investments 9
90 11 68 Gas call options 34 34 Financial liabilities:
DOE decommissioning and decontamination fees 50 43 54 45 Interest rate hedges 24 16 Long-term debt 6,145 6,456 4,779 5,001 Preferred stock subject to mandatory redemption 275 293 275 286 Financial assets are carried at their fair value based on quoted market prices for decommissioning trusts and equity investments, and on financial models for gas call options. Financial liabilities are recorded at cost. Financial liabilities' fair values are based on: termination costs for the interest rate swap; brokers' quotes for long-term debt, preferred stock and the cap; and discounted future cash flows for U.S.
Department of Energy (DOE) decommissioning and decontamination fees. Due to their short maturities, amounts reported for cash equivalents and short-term debt approximate fair value.
Gross unrealized holding gains on financial assets were:
In millions December 31, 1997 1996 Decommissioning trusts:
Municipal bonds
$131
$79 Stocks 190 138 U.S. government issues 91 39 Short-term and other 48 13 460 269 Equity investments 81 57 Total
$541
$326 There were no unrealized holding losses on financial assets for the years presented.
28
Southern California Edison Company Investments Net unrealized gains (losses) in equity investments are recorded as a separate component of shareholder's equity under the caption: Additional paid-in capital and other. Unrealized gains and losses on decommissioning trust funds are recorded in the accumulated provision for decommissioning.
All investments are classified as available-for-sale.
Long-Term Debt California law prohibits SCE from incurring or guaranteeing debt for its nonutility affiliates.
Almost all SCE properties are subject to a trust indenture lien.
SCE has pledged first and refunding mortgage bonds as security for borrowed funds obtained from pollution-control bonds issued by government agencies.
SCE uses these proceeds to finance construction of pollution-control facilities.
Bondholders have limited discretion in redeeming certain pollution-control bonds, and SCE has arranged with securities dealers to remarket or purchase them if necessary.
Debt premium, discount and issuance expenses are amortized over the life of each issue. Under CPUC rate-making procedures, debt reacquisition expenses are amortized over the remaining life of the reacquired debt or, if refinanced, the life of the new debt.
Long-term debt maturities and sinking-fund requirements for the five years are: 1998 -
$693 million; 1999 -
$401 million; 2000 -
$571 million; 2001 -
$646 million; and 2002 -
$446 million.
In December 1997, SCE Funding LLC, a special purpose entity (SPE), of which SCE is the sole member, issued approximately $2.5 billion of rate reduction notes to Bankers Trust Company of California, as certificate trustee for the California Infrastructure and Economic Development Bank Special Purpose Trust SCE-1 (Trust), which is a special purpose entity established by the State of California. The terms of the rate reduction notes generally mirror the terms of the pass-through certificates issued by the Trust, which are known as rate reduction certificates. The proceeds of the rate reduction notes were used by the SPE to purchase from SCE an enforceable right known as transition property. Transition property is a current property right created pursuant to the restructuring legislation and a financing order of the CPUC and consists generally of the right to be paid a specified amount from a non-bypassable tariff levied on residential and small commercial customers. Notwithstanding the legal sale of the transition property by SCE to the SPE, the amounts reflected as assets on SCE's balance sheet have not been reduced by the amount of the transition property sold to the SPE, and the liabilities of the SPE for the rate reduction notes are for accounting purposes reflected as long-term liabilities on the consolidated balance sheet of SCE. SCE used the proceeds from the sale of the transition property to retire debt and equity securities.
The rate reduction notes have maturities ranging from one to 10 years, and bear interest at rates ranging from 5.98% to 6.42%. The rate reduction notes are secured solely by the transition property and certain other assets of the SPE, and there is no recourse to SCE or Edison International.
Although the SPE is consolidated with SCE in the financial statements, as required by generally accepted accounting principles, the SPE is legally separate from SCE, the assets of the SPE are not available to creditors of SCE or Edison International, and the transition property is legally not an asset of SCE or Edison International.
29
Notes to Consolidated Financial Statements Long-term debt consisted of:
In millions December 31, 1997 1996 First and refunding mortgage bonds:
1998 - 2026 (5.45% to 8.375%)
$1,825
$2,725 Rate reduction notes:
1998 - 2007 (5.98% to 6.42%)
2,463 Pollution-control bonds:
1999-2027 (5.4% to 7.2% and variable) 1,202 1,204 Funds held by trustees (2)
(2)
Debentures and notes:
1998-2006 (5.6% to 8.25%)
1,195 1,195 Subordinated debentures:
2044 (8.375%)
100 100 Commercial paper for nuclear fuel 92 112 Long-term debt due within one year (693)
(501)
Unamortized debt discount -
net (37)
(54)
Total
$6,145
$4,779 On January 30, 1998, SCE redeemed $125 million of 8.375% first and refunding mortgage bonds, due 2017. Also, on January 30, 1998, a wholly owned financing subsidiary of SCE redeemed $200 million of 7.375% notes, due 2003.
Short-Term Debt SCE has lines of credit it can use at negotiated or bank index rates. At December 31, 1997, available lines totaled $1.8 billion, with $1.3 billion for short-term debt and $500 million available for the long-term refinancing of certain variable-rate pollution-control debt.
Short-term debt consisted of commercial paper used to finance fuel inventories, balancing account undercollections and general cash requirements. Commercial paper outstanding at December 31, 1997, and 1996, was $415 million and $345 million, respectively. Commercial paper intended to finance nuclear fuel scheduled to be used more than one year after the balance sheet date is classified as long-term debt in connection with refinancing terms under five-year term lines of credit with commercial banks.
Weighted-average interest rates were 6.0% and 5.5% at December 31, 1997, and 1996, respectively.
Note 4. Equity The CPUC regulates SCE's capital structure, limiting the dividends it may pay Edison International. At December 31, 1997, SCE had the capacity to pay $1.4 billion in additional dividends and continue to maintain its authorized capital structure.
Authorized common stock is 560 million shares with no par value. Authorized shares of preferred and preference stock are: $25 cumulative preferred -
24 million; $100 cumulative preferred -
12 million; and preference -
50 million. All cumulative preferred stocks are redeemable.
Mandatorily redeemable preferred stocks are subject to sinking-fund provisions. When preferred shares are redeemed, the premiums paid are charged to common equity.
Preferred stock redemption requirements for the next five years are: 1998 through 2001 -
zero and 2002 -
$105 million.
30
Southern California Edison Company Cumulative preferred stock consisted of:
Dollars in millions, except per-share amounts December 31, 1997 1996 December 31, 1997 Shares Redemption Outstanding Price Not subject to mandatory redemption:
$25 par value:
4.08% Series 1,000,000
$25.50
$ 25
$ 25 4.24 1,200,000 25.80 30 30 4.32 1,653,429 28.75 41 41 4.78 1,296,769 25.80 33 33 5.80 2,200,000 25.25 55 55 7.36 100 Total
$184
$284 Subject to mandatory redemption:
$100 par value:
6.05% Series 750,000
$ 100.00
$ 75
$ 75 6.45 1,000,000 100.00 100 100 7.23 1,000,000 100.00 100 100 Total
$275
$275 In 1997, 4 million shares of Series 7.36% preferred stock were redeemed. In 1995, 750,000 shares of Series 7.58% preferred stock were redeemed. There were no preferred stock issuances or redemptions in 1996.
Note 5. Income Taxes SCE and its subsidiaries will be included in Edison International's consolidated federal income tax and combined state franchise tax returns.
Under income tax allocation agreements, each subsidiary calculates its own tax liability.
Income tax expense includes the current tax liability from operations and the change in deferred income taxes during the year. Investment tax credits are amortized over the lives of the related properties.
31
Notes to Consolidated Financial Statements The components of the net accumulated deferred income tax liability were:
In millions December 31, 1997 1996 Deferred tax assets:
Property-related
$ 227 247 Unrealized gains or losses 273 201 Investment tax credits 192 206 Regulatory balancing accounts 180 298 Decommissioning-related 114 208 Other 335 135 Total
$ 1,321
$ 1,295 Deferred tax liabilities:
Property-related
$ 3,272
$ 3,550 Capitalized software costs 127 122 Other 738 553 Total
$4,137
$ 4,225 Accumulated deferred income taxes -
net
$ 2,816
$ 2,930 Classification of accumulated deferred income taxes:
Included in deferred credits
$ 2,939
$ 3,170 Included in current assets 123 240 The current and deferred components of income tax expense were:
In millions Year ended December 31, 1997 1996 1995 Current:
Federal
$375
$386
$560 State 100 129 165 475 515 725 Deferred-federal and state:
Accrued charges (33)
(14) 1 Depreciation (47)
(14) 21 Investment and energy tax credits -
net (20)
(24)
(25)
Pension reserves (5) 45 (3)
Rate phase-in plan (19)
(32)
(46)
Regulatory balancing accounts 141 34 (118)
State tax -
privilege year 21 (12)
Other 28 (20)
(33) 45 (4)
(215)
Total income tax expense
$520
$511
$510 Classification of income taxes:
Included in operating income
$582
$578
$560 Included in other income (62)
(67)
(50)
The composite federal and state statutory income tax rate was 40.551% for 1997 and 41.045% for 1996 and 1995.
32
Southern California Edison Company The federal statutory income tax rate is reconciled to the effective tax rate below:
S Year ended December 31, 1997 1996 1995 Federal statutory rate 35.0%
35.0%
35.0%
Capitalized software (0.9)
(0.8)
(0.8)
Depreciation and other 6.9 4.5 4.3 Investment and energy tax credits (1.8)
(2.0)
(2.2)
State tax -
net of federal deduction 7.0 7.1 6.5 Effective tax rate 46.2%
43.8%
42.8%
Note 6.
Employee Compensation and Benefit Plans Stock Option Plans Under its Long-Term Incentive Compensation Plan, SCE participates in the use of 8.2 million shares of parent company common stock reserved for potential issuance under various stock compensation programs to directors, officers and senior managers of Edison International and its affiliates. Under these programs, options on 3.7 million shares of Edison International common stock are currently outstanding to officers and senior managers of SCE.
Each option may be exercised to purchase one share of Edison International common stock, and is exercisable at a price equivalent to the fair market value of the underlying stock at the date of grant.
Edison International stock options include a dividend equivalent feature. Generally, for options issued before 1994, amounts equal to dividends accrue on the options at the same time and at the same rate as would be payable on the number of shares of Edison International common stock covered by the options.
The amounts accumulate without interest. For Edison International stock options issued subsequent to 1993, dividend equivalents are subject to reduction unless certain shareholder return performance criteria are met.
Edison International stock options have a 10-year term with one-third of the total award vesting after each of the first three years of the award term. If an optionee retires, dies or is permanently and totally disabled during the three-year vesting period, the unvested options will vest and be exercisable to the extent of 1/36 of the grant for each full month of service during the vesting period. Unvested options of any person who has served in the past on the Edison International or SCE Management Committee will vest and be exercisable upon the member's retirement, death or permanent and total disability. Upon retirement, death or permanent and total disability, the vested options may continue to be exercised within their original terms by the recipient or beneficiary. If an optionee is terminated other than by retirement, death or permanent and total disability, options which had vested as of the prior anniversary date of the grant are forfeited unless exercised within 180 days of the date of termination. All unvested options are forfeited on the date of termination.
SCE measures compensation expense related to stock-based compensation by the intrinsic value method. Compensation expense recorded under the stock-compensation program was $5 million,
$8 million and $4 million for the years 1997, 1996 and 1995, respectively.
Stock-based compensation expense under the fair-value method of accounting would have resulted in pro forma earnings of $602 million, $653 million and $677 million for the years 1997, 1996, and 1995, respectively.
The weighted-average fair value of options granted during 1997 and 1996 was $7.62 per share option and $6.27 per share option, respectively. The weighted-average remaining life of options outstanding as of December 31, 1997, and 1996, was 7 years.
33
Notes to Consolidated Financial Statements The fair value for each option granted, reflecting the basis for the above pro forma disclosures, was determined on the date of grant using the Black-Scholes option-pricing model.
The following assumptions were used in determining fair value through the model:
1997 1996 Expected life 7 years 7 years Risk-free interest rate 6.3% - 6.8%
5.5%
Expected volatility 17%
17%
The recognition of dividend equivalents results in no dividends assumed for purposes of fair-value determination. The application of fair-value accounting to calculate the pro forma disclosures above is not an indication of future income statement effects. The pro forma disclosures do not reflect the effect of fair-value accounting on stock-based compensation awards granted prior to 1995.
Pension Plan SCE has a noncontributory, defined-benefit pension plan that covers employees meeting minimum service requirements. Benefits are based on years of accredited service and average base pay. SCE funds the plan on a level-premium actuarial method. These funds are accumulated in an independent trust. Annual contributions meet minimum legal funding requirements and do not exceed the maximum amounts deductible for income taxes. Prior service costs from pension plan amendments are funded over 30 years. Plan assets are primarily common stocks, corporate and government bonds, and short term investments. In 1996, SCE recorded pension gains from a special voluntary early retirement program.
The plan's funded status was:
In millions December 31, 1977 1996 Actuarial present value of benefit obligations:
Vested benefits
$ 1,577
$ 1,670 Nonvested benefits 126 71 Accumulated benefit obligation 1,703 1,741 Value of projected future compensation levels 391 261 Projected benefit obligation
$ 2,094
$ 2,002 Fair value of plan assets
$ 2,298
$ 2,165 Projected benefit obligation less than plan assets
$ (204)
(163)
Unrecognized net gain 304 300 Unrecognized prior service cost (184)
(199)
Unrecognized net obligation (17-year amortization)
(38)
(43)
Pension liability (asset)
$ (122)
$ (105)
Discount rate 7.0%
7.75%
Rate of increase in future compensation 5.0%
5.0%
Expected long-term rate of return on assets 8.0%
8.0%
34
Southern California Edison Company SCE recognizes pension expense calculated under the actuarial method used for ratemaking.
The components of pension expense were:
In millions Year ended December 31, 1997 1996 1995 Service cost for benefits earned
$ 44
$ 49
$ 57 Interest cost on projected benefit obligation 138 178 156 Actual return on plan assets (369)
(343)
(454)
Net amortization and deferral 222 145 268 Pension expense under accounting standards 35 29 27 Special termination benefits 3
Regulatory adjustment -
deferred 17 22 22 Net pension expense recognized 52 51 52 Settlement gain (121)
Total expense (gain)
$ 52
$ (70)
$ 52 Postretirement Benefits Other Than Pensions Employees retiring at or after age 55 with at least 10 years of service (or those eligible under the 1996 special voluntary early retirement program), are eligible for postretirement health and dental care, life insurance and other benefits. Health and dental care benefits are subject to deductibles, copayment provisions and other limitations.
SCE is amortizing its obligation related to prior service over 20 years. SCE funds these benefits (by contributions to independent trusts) up to tax-deductible limits, in accordance with rate-making practices.
In 1996, SCE recorded special termination expenses due to a special voluntary early retirement program.
Any difference between recognized expense and amounts authorized for rate recovery is not expected to be material (except for the impact of the early retirement program) and will be charged to earnings.
Trust assets are primarily common stocks, corporate and government bonds, and short-term investments.
The funded status of these benefits is reconciled to the recorded liability below:
In millions December 31, 1997 1996 Actuarial present value of benefit obligation:
Retirees
$1,000
$ 928 Employees eligible to retire 45 35 Other employees 488 386 Accumulated benefit obligation
$1,533
$1,349 Fair value of plan assets
$ 815
$ 617 Plan assets less than accumulated benefit obligation
$ 718
$ 732 Unrecognized transition obligation (403)
(430)
Unrecognized net gain (loss)
(244)
(231)
Recorded liability 71
$ 71 Discount rate 7.0%
7.75%
Expected long-term rate of return on assets 8.0%
8.5%
35
Notes to Consolidated Financial Statements The components of postretirement benefits other than pensions expense were:
In millions Year ended December 31, 1997 1996 1995 Service cost for benefits earned
$ 30
$31
$35 Interest cost on benefit obligation 9990 7
Actual return on plan assets (50)
(43)
(28)
Amortization of loss 4
6 1
Amortization of transition obligation 27 Net expense 110 Special termination expense
-7 Total expense3 The assumed rate of future increases in the per-capita cost of health care benefits is 8.5% for 1998, gradually decreasing to 5.25% for 2004 and beyond. Increasing the health care cost trend rate by one percentage point would increase the accumulated obligation as of December 31, 1997, by $255 million annual aggregate service and interest costs by $28 million.
Employee Savings Plan SCE has a 401(k) defined contribution savings plan designed to supplement employees' retirement income.
The plan received employer contributions of $15 million in 1997, $24 million in 1996 and
$19 million in 1995.
Note 7. Jointly Owned Utility Projects SCE owns interests in several generating stations and transmission systems for which each participant provides its own financing. SCEs share of expenses for each project is included in the consolidated statements of income.
The investment in each project, as included in the consolidated balance sheet as of December 31,1997, was:
Plant in Accumulated Under Ownership In millions Service Depreciation Construction Interest Transmission systems:
Eldorado 28 9
3 60%
Pacific Intertie 241 75 1
50 Generating stations:
Four Corners Units 4 and 5 (coal) 459 247 3
48 Mohave (coal) 307 146 5
56 Palo Verde (nuclear) 1,601 665 9
16 San Onofre (nuclear) 4,212 2,210 38 75 Total
$6,848
$3,352
$ 59 36
Southern California Edison Company ote 8. Leases SCE has operating leases, primarily for vehicles, with varying terms, provisions and expiration dates.
Estimated remaining commitments for noncancellable leases at December 31, 1997, were:
Year ended December 31, In millions 1998
$15 1999 12 2000 10 2001 6
2002 3
Thereafter 5
Total
$51 Note 9. Commitments Nuclear Decommissioning 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 Nuclear Regulatory Commission. Decommissioning is estimated to cost $2.1 billion in current-year dollars, based on site-specific studies performed in 1993 for San Onofre and 1992 for Palo Verde. 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 2013 at San Onofre and 2024 at Palo Verde.
San Onofre Unit 1, which shut down in 1992, is expected to be secured until decommissioning begins at the other San Onofre units.
Decommissioning costs, which are accrued and recovered through non-bypassable customer rates over the term of each nuclear facility's operating license, are recorded as a component of depreciation expense. Decommissioning expense was $154 million in 1997, $148 million in 1996 and $151 million in 1995. The accumulated provision for decommissioning was $1.1 billion at December 31, 1997, and
$949 million at December 31, 1996.
The estimated costs to decommission San Onofre Unit 1
($280 million) 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.
Trust investments include:
Maturity December 31, In millions Dates 1997 1996 Municipal bonds 1998-2026
$ 459
$ 400 Stocks 392 549 U.S. government issues 1998-2027 357 212 Short-term and other 2002-2003 163 56 Total
$1,371
$1,217 37
Notes to Consolidated Financial Statements Trust fund earnings (based on specific identification) increase the trust fund balance and the accumulate provision for decommissioning. Net earnings were $54 million, $49 million and $51 million for the years ended 1997, 1996 and 1995, respectively. Proceeds from sales of securities (which are reinvested) were
$595 million for 1997, and $1.0 billion for 1996 and 1995.
Approximately 89% of the trust fund contributions were tax-deductible.
The Financial Accounting Standards Board has issued an exposure draft related to accounting practices for removal costs, including decommissioning of nuclear power plants. The exposure draft would require SCE to report its estimated decommissioning costs as a liability, rather than recognizing these costs over the term of each facility's operating license (current industry practice). SCE does not believe that the changes proposed in the exposure draft would have an adverse effect on its results of operations even after deregulation due to its current and expected future ability to recover these costs through customer rates.
Other Commitments SCE has fuel supply contracts which require payment only if the fuel is made available for purchase.
SCE has power-purchase contracts with certain QFs (cogenerators and small power producers) and other utilities. The OF contracts provide for capacity payments if a facility meets certain performance obligations and energy payments based on actual power supplied to SCE. There are no requirements to make debt-service payments.
SCE has unconditional purchase obligations for part of a power plant's generating output, as well as firm transmission service from another utility. Minimum payments are based, in part, on the debt-service requirements of the provider, whether or not the plant or transmission line is operable. The purchased power contract is not expected to provide more than 5% of current or estimated future operating capacity.
SCE's minimum commitment under both contracts is approximately $193 million through 2017.
Certain commitments for the years 1998 through 2002 are estimated below:
In millions 1998 1999 2000 2001 2002 Projected construction expenditures
$956
$807
$763
$721
$671 Fuel supply contracts 228 146 167 154 163 Purchased-power capacity payments 686 711 714 716 714 Unconditional purchase obligations 9
9 10 9
10 Note 10. Contingencies In addition to the matters disclosed in these notes, SCE is involved in legal, tax and regulatory proceedings before various courts and governmental agencies regarding matters arising in the ordinary course of business. SCE believes the outcome of these proceedings will not materially affect its results of operations or liquidity.
Environmental Protection SCE is subject to numerous environmental laws and regulations, which require it to incur substantial costs to operate existing facilities, construct and operate new facilities, and mitigate or remove the effect of past operations on the environment.
38
Southern California Edison Company
.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 undiscounted amounts). While SCE has numerous insurance policies that it believes may provide coverage for some of these liabilities, it does not recognize recoveries in its financial statements until they are realized.
In connection with the issuance of the San Onofre Units 2 and 3 operating permits, SCE reached an agreement with the California Coastal Commission in 1991 to restore certain marine mitigation sites. The restorations include two sites: designated wetlands and the construction of an artificial kelp reef off the California coast. After SCE requested certain modifications to the agreement, the Coastal Commission issued a final ruling in April 1997 to reduce the scope of remediations. SCE elected to pay for the costs of marine mitigation in lieu of placing the funds into a trust. Rate recovery of these costs is occurring through the San Onofre incentive pricing plan discussed in Note 1 to the Consolidated Financial Statements.
SCE's recorded estimated minimum liability to remediate its 50 identified sites is $178 million, which includes $75 million for the two sites discussed above. 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 $246 million. The upper limit of this range of costs was estimated using assumptions least favorable to SCE among a range of reasonably possible outcomes.
The CPUC allows SCE to recover environmental-cleanup costs at 41 of its sites, representing $91 million of its recorded liability, through an incentive mechanism (SCE may request to include additional sites).
Under this mechanism, SCE will recover 90% of cleanup costs through customer rates; shareholders fund the remaining 10%, with the opportunity to recover these costs from insurance carriers and other third parties. SCE has successfully settled insurance claims with all responsible carriers. Costs incurred at SCE's remaining sites are expected to be recovered through customer rates. SCE has recorded a regulatory asset of $153 million for its estimated minimum environmental-cleanup costs expected to be recovered through customer rates. This amount includes $60 million of marine mitigation costs remaining to be recovered through the San Onofre incentive pricing plan.
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 now 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 1997 were $10 million.
Based on currently available information, SCE believes it is unlikely that it will incur amounts in excess of the upper limit of the estimated range 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 financial position.
There can be no assurance, however, that future 39
Notes to Consolidated Financial Statements developments, including additional information about existing sites or the identification of new sites, wiW not require material revisions to such estimates.
Nuclear Insurance Federal law limits public liability claims from a nuclear incident to $8.9 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 Nuclear Regulatory Commission exempted San Onofre Unit 1 from this secondary level, effective June 1994. The maximum deferred premium for each nuclear incident is $79 million per reactor, but not more than $10 million per reactor may be charged in any one year for each incident. Based on its ownership interests, SCE could be required to pay a maximum of
$158 million per nuclear incident. However, it would have to pay no more than $20 million per incident in any one year. Such amounts include a 5% surcharge if additional funds are needed to satisfy public liability claims and are subject to adjustment for inflation. If the public liability limit above is insufficient, federal regulations may impose further revenue-raising measures to pay claims, including a possible additional assessment on all licensed reactor operators.
Property damage insurance covers losses up to $500 million, including decontamination costs, at San Onofre and Palo Verde. Decontamination liability and property damage coverage exceeding the primary
$500 million also has been purchased in amounts greater than federal requirements.
Additional insurance covers part of replacement power expenses during an accident-related nuclear unit outage.
These policies are issued primarily by mutual insurance companies owned by utilities with nuclea facilities. If losses at any nuclear facility covered by the arrangement were to exceed the accumulate funds for these insurance programs, SCE could be assessed retrospective premium adjustments of up to
$28 million per year. Insurance premiums are charged to operating expense.
Quarterly Financial Data 1997 1996 In millions Total Fourth Third Second First Total Fourth Third Second First Operating revenue
$7,953
$1,980
$2,434
$1,844
$1,695
$7,583 $1,866
$2,346
$1,611
$1,760 Operating income 1,060 248 349 229 234 1,133 231 382 257 263 Net income 606 123 233 129 121 655 121 256 131 147 Earnings available for common stock 576 116 226 122 112 621 113 247 123 138 Common dividends declared 1,829 1,266 217 171 175 735 196 178 180 181 40
Responsibility for Financial Reporting O
The management.of Southern California Edison Company (SCE) is responsible for the integrity and objectivity of the accompanying financial statements. The statements have been prepared in accordance with generally accepted accounting principles applied on a consistent basis and are based, in part, on management estimates and judgment.
SCE maintains systems of internal control to provide reasonable, but not absolute, assurance that assets are safeguarded, transactions are executed in accordance with management's authorization and the accounting records may be relied upon for the preparation of the financial statements. There are limits inherent in all systems of internal control, the design of which involves management's judgment and the recognition that the costs of such systems should not exceed the benefits to be derived. SCE believes its systems of internal control achieve this appropriate balance. These systems are augmented by internal audit programs through which the adequacy and effectiveness of internal controls and policies and procedures are monitored, evaluated and reported to management.
Actions are taken to correct deficiencies as they are identified.
SCE's independent public accountants, Arthur Andersen LLP, are engaged to audit the financial statements in accordance with generally accepted auditing standards and to express an informed opinion on the fairness, in all material respects, of SCE's reported results of operations, cash flows and financial position.
As a further measure to assure the ongoing objectivity of financial information, the audit committee of the board of directors, which is composed of outside directors, meets periodically, both jointly and separately, with management, the independent public accountants and internal auditors, who have restricted access to the committee. The committee recommends annually to the board of directors the appointment of a firm of independent public accountants to conduct audits of its financial statements; considers the independence of such firm and the overall adequacy of the audit scope and SCE's systems of internal control; reviews financial reporting issues; and is advised of management's actions regarding financial reporting and internal control matters.
SCE maintains high standards in selecting, training and developing personnel to assure that its operations are conducted in conformity with applicable laws and is committed to maintaining the highest standards of personal and corporate conduct.
Management maintains programs to encourage and assess compliance with these standards.
Richard K. Bushey John E. Bryson Vice President Chairman of the Board and Controller and Chief Executive Officer January 30, 1998 41
Report of Independent Public Accountants Southern California Edison Company To the Shareholders and the Board of Directors, Southern California Edison Company:
We have audited the accompanying consolidated balance sheets of Southern California Edison Company (SCE, a California corporation) and its subsidiaries as of December 31, 1997, and 1996, and the related consolidated statements of income, retained earnings and cash flows for each of the three years in the period ended December 31, 1997.
These financial statements are the responsibility of SCE's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of SCE and its subsidiaries as of December 31, 1997, and 1996, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1997, in conformity with generally accepted accounting principles.
ARTHUR ANDERSEN LLP Los Angeles, California January 30, 1998 42
Board of Directors Southern California Edison Cornan John E. Bryson Carl F. Huntsinger E. L. Shannon, Jr.
Chairman of the Board and CEO, General Partner, Retired Chairman of the Board, Edison International and SCE DAE Lmited Partnership Ltd.,
Santa Fe International Corporation, Ojai, California Alhambra, California Winston H. Chen Chairman of the Paramitas Foundation Charles D. Miller Robert H. Smith and Chairman of Paramitas Chairman of the Board and CEO, Managing Director, Investment Corporation, Avery Dennison Corporation, Smith and Crowley Incorporated, Santa Clara, California Pasadena, California Pasadena, California Warren Christopher Luis F. Nogales Thomas C. Sutton Senior Partner, President, Chairman of the Board and CEO, O'Melveny & Myers, Nogales Partners, Pacific fe Insurance Company, Los Angeles, California Los Angeles, California Newport Beach, California Stephen E. Frank Ronald L. Olson Daniel M. Tellep President and Chief Operating Senior Partner, Retired Chairman of the Board, Officer, SCE Munger, Tolles and Olson, Lockheed Martin Corporation, Los Angeles, California Bethesda, Maryland Camilla C. Frost*
Trustee, Chandler Trusts, J. J. Pnoles James D. Watkins Director and Secretary-Treasurer, Retired Chairman of the Admiral USN, Retired Chandis Securities Company, Board and CEO, President, Joint Oceanographic Los Angeles, California First Interstate Bancorp, Institutions, Inc. and President, Los Angeles, California Consortium for Oceanographic Joan C. Hanley Research and Education General Partner, James M. Rosser Washington, D.C.
Miranionte Vineyards, President, Rancho Palos Verdes California California State University, Los Angeles, Edward Zapanta, M.D.
Los Angeles, California Physician and Neurosurgeon, Retiring on April 16,1998 Torrance, California Management Team John E. Bryson Robert G. Foster Lawrence D. Hamlin Chairman of the Board and CEO Senior Vice President, Vice President, Power Production Public Affairs Stephen E. Frank Thomas J. Higgins President and Chief Operating Officer Richard M. Rosenblum Vice President, Senior Vice President, Corporate Communications Bryant C. Danner T&D Wires Business Unit Executive Vice President and R. W. Krieger General Counsel Emiko Banfield Vice President, Nuclear Generation Vice President, Shared Services Alan J. Fohrer J. Michael Mendez Executive Vice President and Pamela A. Bass Vice President, Labor Relations Chief Financial Officer Vice President, Customer Solutions Business Unit Dwight E. Nunn Harold B. Ray Vice President, Nuclear Engineering Executive Vice President, Richard K. Bushey and Technical Services Generation Business Unit Vice President and Controller Frank J. Quevedo Theodore F. Craver, Jr.
Bruce C. Foster Vice President, Equal Opportunity Senior Vice President and Treasurer Vice President, San Francisco Regulatory Affairs Mahvash Yazdi John R. Fielder Vice President and Chief Senior Vice President, Lillian R. Gorman Information Officer Regulatory Policy and Affairs Vice President, Human Resources Beverly P. Ryder Corporate Secretary 43
EDISO ISN NERAIOALcmpn j'thern
~
~
ClfriEdso 6,-.
4 WantGoeAeu Roeed Caioni 17
Shareholder Information Annual Meeting of Shareholders Thursday, April 16, 1998 10:00 a.m.
The Industry Hills Sheraton Resort and Conference Center One Industry Hills Parkway City of Industry, California Stock Listing and Trading Information SCE Preferred Stock The American and Pacific stock exchanges use the ticker symbol SCE. Previous day's closing prices, when traded, are listed in the daily newspapers in the American Stock Exchange table under the symbol SoCalEd. The 6.05%, 6.45% and 7.23% series are not listed.
Where to Buy and Sell Stock The listed preferred stocks may be purchased through any brokerage firm. Firms handling unlisted series can be located through your broker.
Transfer Agent and Registrar Southern California Edison Company maintains shareholder records and is transfer agent and registrar for SCE preferred stock.
Shareholders may call Shareholder Services, (800) 347-8625, between 8:00 a.m. and 4:00 p.m. (Pacific time) every business day, regarding:
stock transfer and name-change requirements; address changes, including dividend addresses; electronic deposit of dividends; taxpayer identification number submission or changes; duplicate 1099 forms and W-9 forms; notices of and replacement of lost or destroyed stock certificates; dividend checks; requests to eliminate multiple annual report mailings; and request access to online account information via Edison International's Internet Home Page, www.edisonx.com The address of Shareholder Services is:
P.O. Box 400, Rosemead, California 91770-0400 FAX: (626) 302-4815