ITEM 1. BUSINESS
Description of Business A description of Enova Corporation and its subsidiaries, including a discussion on the proposed business combination with Pacific Enterprises, is given in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein. Additional information on the business combination is described in Note 1 of the "Notes to Consolidated Financial Statements" herein.
GOVERNMENT REGULATION
Enova Corporation Enova Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the Public Utility Holding Company Act of 1935 ("Holding Company Act") on the basis that Enova Corporation and San Diego Gas & Electric are incorporated in the same state and their business is predominately intrastate in character and carried on substantially in the state of incorporation. It is necessary for Enova Corporation to file an annual exemption statement with the Securities and Exchange Commission (SEC), and the exemption may be revoked by the SEC upon a finding that the exemption may be detrimental to the public interest or the interest of investors or consumers. Enova Corporation has no intention of becoming a registered holding company under the Holding Company Act.
Enova Corporation is not a public utility under the laws of the State of California and is not subject to regulation as such by the California Public Utilities Commission (CPUC). See "State Regulation" below for a description of the regulation of SDG&E by the CPUC. However, the CPUC decision authorizing SDG&E to reorganize into a holding company structure contains certain conditions, which, among other things, provide the CPUC access to the portion of books and records of Enova Corporation and its affiliates that relate to transactions with SDG&E; require Enova Corporation and its subsidiaries to employ accounting and other procedures and controls to facilitate full review by the CPUC and to protect against subsidization by SDG&E's customers of non-utility activities; require that all transfers of market, technological or similar data from SDG&E to Enova Corporation or its affiliates are made at the higher of the fully-loaded cost or market value; preclude SDG&E from guaranteeing any obligations of Enova Corporation without prior written consent from the CPUC; provide for royalty payments to be paid by Enova Corporation or its other subsidiaries in connection with the transfer of product rights, patents, copyrights or similar legal rights from SDG&E; and prevent Enova Corporation and its other subsidiaries from providing certain facilities and equipment to SDG&E except through competitive bidding. In addition, the decision provides that SDG&E shall maintain a balanced capital structure in accordance with prior CPUC decisions, that SDG&E's dividend policy shall continue to be established by SDG&E's board of directors as though SDG&E were a comparable stand- alone utility company, and that the capital requirements of SDG&E, as determined to be necessary to meet SDG&E's service obligations, shall be given first priority by the boards of directors of Enova Corporation and SDG&E.
In December 1997 the CPUC issued a decision on the rules governing transactions between all of California's regulated utilities and their affiliates that are not regulated by the CPUC. A discussion of these
rules is included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
San Diego Gas & Electric
Local Regulation San Diego Gas & Electric has separate electric and gas franchises with the two counties and the 25 cities in its service territory. These franchises allow SDG&E to locate facilities for the transmission and distribution of electricity and gas in the streets and other public places. The franchises do not have fixed terms, except for the electric and gas franchises with the cities of Chula Vista (expiring in 1998), Encinitas (2012), San Diego (2021) and Coronado (2028); and the gas franchises with the city of Escondido (2036) and the county of San Diego (2030). Negotiations for a new agreement with Chula Vista are currently in progress.
State Regulation The CPUC consists of five members appointed by the governor and confirmed by the senate for six-year terms. The CPUC regulates SDG&E's rates and conditions of service, sales of securities, rate of return, rates of depreciation, uniform systems of accounts, examination of records, and long-term resource procurement. The CPUC also conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition and the environment, to determine its future policies.
The California Energy Commission (CEC) has discretion over electric- demand forecasts for the state and for specific service territories. Based upon these forecasts, the CEC determines the need for additional energy sources and for conservation programs. The CEC sponsors alternative-energy research and development projects, promotes energy conservation programs, and maintains a state-wide plan of action in case of energy shortages. In addition, the CEC certifies power-plant sites and related facilities within California.
Federal Regulation The Federal Energy Regulatory Commission (FERC) regulates transmission access, the uniform systems of accounts, rates of depreciation and electric rates involving sales for resale. The FERC also regulates the interstate sale and transportation of natural gas.
The Nuclear Regulatory Commission (NRC) oversees the licensing, construction and operation of nuclear facilities. NRC regulations require extensive review of the safety, radiological and environmental aspects of these facilities. Periodically, the NRC requires that newly developed data and techniques be used to re-analyze the design of a nuclear power plant and, as a result, requires plant modifications as a condition of continued operation in some cases.
Licenses and Permits SDG&E obtains a number of permits, authorizations and licenses in connection with the construction and operation of its generating plants. Discharge permits, San Diego Air Pollution Control District permits and NRC licenses are the most significant examples. The licenses and permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals are granted for a term less than the expected life of the facility. They require periodic renewal, which results in continuing regulation by the granting agency.
Other regulatory matters are described throughout this report.
SOURCES OF REVENUE
(In Millions of Dollars) 1997 1996 1995 - ------------------------------------------------------------------ SDG&E revenue by type of customer:
Electric- Residential $ 674 $ 642 $ 610 Commercial 670 621 589 Industrial 264 259 250 Other 162 69 55 ------ ------ ------ Total Electric 1,770 1,591 1,504 ------ ------ ------ Gas- Residential 241 210 189 Commercial 82 69 60 Industrial 38 32 25 Other 37 37 36 ------ ------ ------ Total Gas 398 348 310 ------ ------ ------ Total SDG&E 2,168 1,939 1,814 ------ ------ ------ Other 49 54 57 ------ ------ ------ Total $2,217 $1,993 $1,871 ====== ====== ======
Industry segment information is contained in "Statements of Consolidated Financial Information by Segments of Business" herein.
CONSTRUCTION EXPENDITURES
Construction expenditures are described in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
ELECTRIC OPERATIONS
Introduction In September 1996 the state of California enacted a law restructuring California's electric utility industry (AB 1890). The legislation adopts the December 1995 CPUC policy decision restructuring the industry to stimulate competition and reduce rates. This is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 10 of the "Notes to Consolidated Financial Statements" herein.
Resource Planning SDG&E's ability to provide energy at the lowest possible cost has been based on a combination of production from its own plants and purchases from other producers. The purchases have been a combination of short- term and long-term contracts and spot-market purchases. Most resource acquisitions are obtained through a competitive bidding process. In December 1994 the CPUC issued its Biennial Resource Plan Update (BRPU) decision ordering SDG&E, Pacific Gas & Electric (PG&E), and Southern California Edison (Edison) to allow qualified non-utility power
producers that cogenerate or use renewable energy technologies to bid for a portion of the utilities' future capacity needs. As a result of the decision, SDG&E would be required to enter into contracts (ranging in term from 17 to 30 years) to purchase an additional 500 megawatts (mw) of power at an estimated cost of $2.3 billion beginning in 1997. Prices under these contracts could significantly exceed the future market price. In February 1995 the FERC issued an order declaring the BRPU auction procedures unlawful under federal law. In July 1995 the CPUC issued a ruling encouraging SDG&E, PG&E and Edison to reach settlements with the auction winners. In October 1997 SDG&E filed an application with the CPUC seeking approval of the settlements it reached with three of its five auction winners. Settlement discussions with the other two are ongoing. To date, no purchases under the BRPU contracts have been made.
Additional information concerning resource planning is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 9 and 10 of the "Notes to Consolidated Financial Statements" herein.
Electric Resources Based on generating plants in service and purchased-power contracts in place, the net mw of electric power available to SDG&E at February 28, 1998 are as follows:
Source Net mw -------------------------------------------------- Gas/oil generating plants 1,641 Combustion turbines 332 Nuclear generating plants 430 Long-term contracts with other utilities 325 Contracts with others (94) 593 ----- Total 3,321 =====
SDG&E's system peak demand reached an all-time record of 3,668 mw on September 4, 1997, when the net system capability, including power purchases, was 4,102 mw. The previous record was 3,335 mw which was reached on August 17, 1992.
Gas/Oil Generating Plants: SDG&E's South Bay (Chula Vista, California) and Encina (Carlsbad, California) power plants are equipped to burn either natural gas or fuel oil. The four South Bay units went into operation between 1960 and 1971 and can generate 690 mw. The five Encina units began operation between 1954 and 1978 and can generate 951 mw. SDG&E sold and leased back Encina Unit 5 (330 mw) in 1978. The lease term is through 2004, with renewal options for up to 15 additional years.
SDG&E has 19 combustion turbines that were placed in service from 1966 to 1979. They are located at various sites and are used only in times of peak demand.
San Onofre Nuclear Generating Station (SONGS): SDG&E owns 20 percent of the three nuclear units at SONGS (south of San Clemente, California). The cities of Riverside and Anaheim own a total of 5 percent of SONGS 2 and 3. Edison owns the remaining interests and operates the units.
SONGS 1 was removed from service in November 1992 when the CPUC issued a decision to permanently shut down the unit. At that time SDG&E began the
recovery of its remaining capital investment, with full recovery completed in April 1996. SDG&E and Edison filed a decommissioning plan in November 1994, although final decommissioning is not scheduled to occur until 2013 when SONGS 2 and 3 are also decommissioned. The unit's spent nuclear fuel has been removed from the reactor and stored on-site. In March 1993 the NRC issued a Possession-Only License for SONGS 1, and the unit was placed in a long-term storage condition in May 1994.
SONGS 2 and 3 began commercial operation in August 1983 and April 1984, respectively. SDG&E's share of the capacity is 214 mw of SONGS 2 and 216 mw of SONGS 3.
During 1997 SDG&E spent $7 million on capital modifications and additions and expects to spend $14 million in 1998. SDG&E deposits funds in an external trust to provide for the future dismantling and decontamination of the units. The shutdown of SONGS 1 does not affect contributions to the trust.
Additional Information: Additional information concerning SDG&E's power plants, the SONGS units, nuclear decommissioning and the CPUC's industry restructuring proposal (including SDG&E's plan to auction its electric generation assets) is provided immediately below and in "Environmental Matters," "Electric Properties," "Legal Proceedings," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 5, 9 and 10 of the "Notes to Consolidated Financial Statements" herein.
Purchased Power: The following table lists contracts with the various suppliers:
Megawatt Supplier Period Commitment Source - ----------------------------------------------------------------------- Long-Term Contracts with Other Utilities:
Portland General Through December 1998 50 Hydro storage Electric (PGE) Through December 2013 75 Coal
Public Service Company of New Mexico (PNM) Through April 2001 100 System supply
PacifiCorp Through December 2001 100 System Supply ----- Total 325 ===== Contracts with Others:
LG&E Power Marketing Through December 2001 150 System Supply
Goal Line Limited Through December 2025 50 Cogeneration Partnership
Illinova Power Marketing Through December 1999 200 System Supply
Applied Energy Through December 2019 102 Cogeneration
Yuma Cogeneration Through June 2024 50 Cogeneration
Other (89) Various 41 Cogeneration ------ Total 593 ======
On the contracts with PGE (sourced from coal) and PNM, SDG&E pays a capacity charge plus a charge based on the amount of energy received. SDG&E also has a contract with PGE for available hydro storage service. Charges under these contracts are based on the selling utility's costs, including a return on and depreciation of the utility's rate base (or lease payments in cases where the utility does not own the property), fuel expenses, operating and maintenance expenses, transmission expenses, administrative and general expenses, and state and local taxes. Charges under contracts from PacifiCorp, LG&E and Illinova are for firm energy only and are based on the amount of energy received. The prices under these contracts are at market value at the time the contracts were negotiated. Costs under the remaining contracts (all with Qualifying Facilities) are based on SDG&E's avoided cost.
Additional information concerning SDG&E's purchased-power contracts is described immediately below, and in "Legal Proceedings," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 9 and 10 of the "Notes to Consolidated Financial Statements" herein.
Electric Generation Divestiture In November 1997 SDG&E's board of directors approved a plan to auction the company's power plants and other electric generating assets, enabling SDG&E to continue to concentrate its business on the transmission and distribution of electricity and natural gas as California opens its electric utility industry to competition in 1998. The plan includes the divestiture of SDG&E's fossil power plants (Encina and South Bay) and its combustion turbines, as well as its 20-percent interest in SONGS and its portfolio of long-term power contracts, including those with qualifying facilities. Additional information describing SDG&E's plan to divest of its electric generating assets is
described in Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 9 and 10 of the "Notes to Consolidated Financial Statements" herein.
Power Pools In 1964 SDG&E, PG&E, and Edison entered into the California Power Pool Agreement. It provided for the transfer of electrical capacity and energy by purchase, sale or exchange during emergencies and at other mutually determined times. Due to electric industry restructuring (discussed below) the California Power Pool was terminated by the FERC in May 1997. However, SDG&E, Edison, PG&E and the Los Angeles Department of Water and Power will continue to abide by the provisions of the existing California Statewide Emergency Plan for sharing capacity and energy in the event of a severe resource emergency until the PX and ISO are fully operational.
SDG&E is a participant in the Western Systems Power Pool (WSPP), which includes an electric power and transmission rate agreement with utilities and power agencies located throughout the United States and Canada. More than 150 investor-owned and municipal utilities, state and federal power agencies, energy brokers, and power marketers share power and information in order to increase efficiency and competition in the bulk power market. Participants are able to target and coordinate delivery of cost-effective sources of power from outside their service territories through a centralized exchange of information. Although the extent has not yet been determined, the status of the WSPP is likely to change due to industry restructuring and the initiation of the PX and ISO.
Transmission Arrangements In addition to interconnections with other California utilities, SDG&E has firm transmission capabilities for purchased power from the Northwest, the Southwest and Mexico.
Pacific Intertie: The Pacific Intertie, consisting of AC and DC transmission lines, enables SDG&E to purchase and receive surplus coal and hydroelectric power from the Northwest. SDG&E, PG&E, Edison and others share transmission capacity on the Pacific Intertie under an agreement that expires in July 2007. SDG&E's share of the intertie was 266 MW. Due to electric industry restructuring (discussed below), the operating rights of SDG&E, Edison and PG&E on the Pacific Intertie have been transferred to the ISO.
Southwest Powerlink: SDG&E's 500-kilovolt Southwest Powerlink transmission line, which is shared with Arizona Public Service Company and Imperial Irrigation District, extends from Palo Verde, Arizona to San Diego and enables SDG&E to import power from the Southwest. SDG&E's share of the line is 931 mw, although it can be less, depending on specific system conditions.
Mexico Interconnection: Mexico's Baja California Norte system is connected to SDG&E's system via two 230-kilovolt interconnections with firm capability of 408 mw. SDG&E uses these interconnections for transactions with Comision Federal de Electricidad (CFE), Mexico's government-owned electric utility.
Transmission Access As a result of the enactment of the National Energy Policy Act of 1992, the FERC has established rules to implement the Act's transmission- access provisions. These rules specify FERC-required procedures for others' requests for transmission service. In October 1997 the FERC
approved the transfer of control by the California investor-owned utilities (IOUs) of their transmission facilities to the ISO. Beginning on March 31, 1998 the ISO will be responsible for the operation and control of the transmission lines. Additional information regarding the ISO and transmission access is discussed below and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
Power Exchange and Independent System Operator Under the CPUC's electric restructuring decision, beginning on March 31, 1998 customers will have the option to buy their electricity through an independent exchange that will obtain power from qualifying facilities, nuclear units and, lastly, from the lowest-bidding suppliers. The PX will serve as a wholesale power pool allowing all energy producers to participate competitively. The ISO will schedule power transactions and access to the transmission system. As discussed above, California's IOUs will transfer the operational control of their transmission facilities to the ISO, which is under FERC jurisdiction. Additional information regarding the PX and ISO is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
Fuel and Purchased-Power Costs The following table shows the percentage of each electric fuel source used by SDG&E and compares the costs of the fuels with each other and with the total cost of purchased power:
Percent of Kwhr Cents per Kwhr - ----------------------------------------------------------------------- 1997 1996 1995 1997 1996 1995 ----- ----- ----- ---- ---- ---- Natural gas 19.8% 22.8% 21.7% 3.3 2.8 2.3 Nuclear fuel 11.8 19.6 16.5 0.6 0.5 0.5 Fuel oil 0.1 1.1 0.1 2.4 2.2 2.1 ----- ----- ----- Total generation 31.7 43.5 38.3 Purchased power - net 68.3 56.5 61.7 2.8 3.1 3.3 ----- ----- ----- Total 100.0% 100.0% 100.0% ===== ===== =====
The cost of purchased power includes capacity costs as well as the costs of fuel. The cost of natural gas includes transportation costs. The costs of natural gas, nuclear fuel and fuel oil do not include SDG&E's capacity costs. While fuel costs are significantly less for nuclear units than for other units, capacity costs are higher.
Electric Fuel Supply Natural Gas: Information concerning natural gas is provided in "Natural Gas Operations" herein.
Nuclear Fuel: The nuclear-fuel cycle includes services performed by others. These services and the dates through which they are under contract are as follows:
Mining and milling of uranium concentrate 2003 Conversion of uranium concentrate to uranium hexafluoride 2003 Enrichment of uranium hexafluoride(1) 2003 Fabrication of fuel assemblies 2003 Storage and disposal of spent fuel(2) --
(1) SDG&E has a contract with Urenco, a British consortium, for enrichment services through 2003.
(2) Spent fuel is being stored at SONGS, where storage capacity will be adequate at least through 2006. If necessary, modifications in fuel- storage technology can be implemented to provide on-site storage capacity for operation through 2013, the expiration date of the NRC operating license. The plan of the U.S. Department of Energy (DOE) is to provide a permanent storage site for the spent nuclear fuel by 2010.
Pursuant to the Nuclear Waste Policy Act of 1982, SDG&E entered into a contract with the DOE for spent-fuel disposal. Under the agreement, the DOE is responsible for the ultimate disposal of spent fuel. SDG&E is paying a disposal fee of $0.91 per megawatt-hour of net nuclear generation. Disposal fees average $3 million per year.
To the extent not currently provided by contract, the availability and the cost of the various components of the nuclear-fuel cycle for SDG&E's nuclear facilities cannot be estimated at this time.
Additional information concerning nuclear-fuel costs is discussed in Note 9 of the "Notes to Consolidated Financial Statements" herein.
Fuel Oil: SDG&E has no long-term commitments to purchase fuel oil. The use of fuel oil is dependent upon price differences between it and natural gas, and air-emission limitations associated with the San Diego Air Pollution Control District's Rule 69. Additional information concerning air-emission restrictions, including Rule 69, is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein. During 1997 SDG&E burned 49,000 barrels of fuel oil.
NATURAL-GAS OPERATIONS
SDG&E purchases natural gas for resale to its customers and for fuel in its generating plants. All natural gas is delivered to SDG&E under a transportation and storage agreement with Southern California Gas Company (SoCalGas) through two transmission pipelines with a combined capacity of 454 million cubic feet per day. On December 12, 1997 SDG&E's natural-gas usage, which included consumption by both customers and SDG&E's power plants, reached a new one-day peak of 555 million cubic feet (mcf). The previous record of 500 mcf had been set on November 28, 1994.
During 1997 SDG&E purchased approximately 98 billion cubic feet of natural gas. The majority of SDG&E's natural-gas requirements are met through contracts of less than one year. SDG&E purchases natural gas primarily from various spot-market suppliers and from suppliers under short-term contracts. These supplies originate in New Mexico, Oklahoma and Texas, and are transported to the SoCalGas pipeline at the California border by El Paso Natural Gas Company and by Transwestern Pipeline Company. SDG&E also has long-term contracts for natural gas with four Canadian suppliers. Three of these suppliers have ceased deliveries due to legal disputes. Natural gas from Canada is transported to SDG&E's system over Alberta Natural Gas, Pacific Gas Transmission, and PG&E pipelines. The natural-gas transportation contracts have varying terms through 2023.
Additional information concerning SDG&E's gas operations is provided under "Legal Proceedings," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 9 of the "Notes to Consolidated Financial Statements" herein.
RATE REGULATION
Industry Restructuring In September 1996 the state of California enacted a law restructuring California's electric utility industry. The legislation adopts the December 1995 CPUC decision that restructures the industry to stimulate competition and reduce rates. Electric industry restructuring is discussed in detail in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 10 of the "Notes to Consolidated Financial Statements" herein.
Cost of Capital A description of SDG&E's cost of capital mechanism, the Market-Indexed Capital Adjustment Mechanism (MICAM), is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein. MICAM eliminates the need to file an annual cost of capital application.
Electric Fuel Costs and Sales Volumes Rates to recover electric-fuel and purchased-power costs had previously been determined in the Energy Cost Adjustment Clause (ECAC) proceeding. The Electric Revenue Adjustment Mechanism (ERAM) compensated for variations in sales volume compared to the estimates used for setting the non-fuel component of rates. However, both ECAC and ERAM have been eliminated as part of electric industry restructuring. The elimination of ECAC and ERAM causes the revenues associated with electric fuel costs and sales volumes to be market driven. Although no effect occurred for the full year, quarterly earnings significantly fluctuated in 1997. Additional information on balancing accounts is discussed below in "Balancing Accounts" and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
Natural-Gas Costs and Sales Volumes Natural-gas commodity rates are set monthly based on market prices. Under traditional ratemaking, natural-gas rates were adjusted annually based on a forecast of natural-gas prices. This resulted in rate stability, but also contributed to significant accumulations in the Purchased Gas Account (PGA). Rates to recover the cost of transporting natural gas to SDG&E are determined in the Biennial Cost Allocation Proceeding (BCAP). The BCAP proceeding normally occurs every two years and is updated in the interim year for purposes of amortizing any accumulation in the balancing accounts. The natural-gas balancing accounts include the PGA for natural-gas costs and the Gas Fixed Cost Account (GFCA) for sales volumes. Balancing account coverage includes both core customers (primarily residential and commercial customers) and noncore customers (primarily large, industrial customers). However, SDG&E does not receive balancing account treatment on 25 percent of noncore GFCA overcollections and undercollections.
Balancing Accounts Until 1997, the CPUC required electric balancing accounts for fuel and purchased energy costs and for sales volumes, setting balancing account rates based on estimated costs and sales volumes. Revenues were adjusted upward or downward to reflect the differences between authorized and actual volumes and costs. These differences were accumulated in the balancing accounts and represented amounts to be either recovered from customers or returned to them. As of December 31, 1997 net ECAC and ERAM overcollections of $130 million have been transferred to the interim transition cost balancing account to be applied to transition cost recovery. Additional information on balancing accounts is discussed in "Management's Discussion and Analysis of Financial Condition and Results
of Operations" and in Note 2 of the "Notes to Consolidated Financial Statements" herein.
Performance-Based Ratemaking CPUC policies continue to move away from traditional cost-of-service regulation and toward incentive mechanisms. SDG&E implemented performance-based ratemaking (PBR) in 1993 for natural-gas procurement and transportation, and for electric generation and purchased energy. These mechanisms measure SDG&E's ability to purchase and transport natural gas, and to generate or purchase energy at the lowest possible cost, by comparing SDG&E's performance against various market benchmarks. In 1994 SDG&E implemented its Base Rates PBR, which includes the measurement of company performance indicators against a set of predetermined standards. Under all of the PBR mechanisms, SDG&E's shareholders and customers share in any savings or excess costs within predetermined ranges. A discussion of the current status of these programs is contained in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
Energy Conservation Programs Over the past several years, SDG&E has promoted conservation programs to encourage efficient use of energy. The programs are designed to use energy-efficiency measures that will reduce customers' energy costs and ultimately reduce the need to build additional power plants. The costs of these programs have been recovered from customers. The programs contained an incentive mechanism that could increase or decrease SDG&E's earnings, depending upon the performance of the programs in meeting specified efficiency and expenditure targets. However, consistent with the industry trend toward increased competition, the CPUC has issued a decision that the IOUs are to transfer the control of their energy- efficiency programs to the competitive market beginning in October 1998. The decision directs the creation of an oversight board that will develop program policies and procedures and select program administrators. The utilities no longer will be involved with program delivery to customers, but will be allowed to bid to become administrators. Until the transition to a fully competitive market is complete, customers will continue to provide the funding. A discussion of the status of these programs is contained in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
Low-Emission Vehicle Programs SDG&E has conducted a CPUC-approved natural-gas-vehicle (NGV) program since 1991. The program includes building refueling stations, demonstrating new technology, providing incentives and converting portions of SDG&E's vehicle fleet to natural gas. The cost of this program is being recovered in natural-gas rates. In November 1995 the CPUC issued its decision authorizing funding for limited electric- vehicle (EV) and NGV programs through the year 2000 to allow recovery of costs for operation and maintenance of SDG&E's EV and NGV fleets and NGV fueling stations, and to allow recovery of transition costs to meet existing commitments to customers. The decision requires the sale of SDG&E's NGV fueling stations located on customer property within six years. The CPUC approved a six-year program that provides a total of $5.3 million for SDG&E's electric-vehicle program and $6.7 million for its natural-gas-vehicle program over the six-year period.
Electric Rates The average price per kilowatt-hour (kwh) charged to electric customers was 9.8 cents in 1997 and 9.6 cents in 1996. California's electric restructuring law (AB 1890) included a rate freeze for all customers. Beginning on January 1, 1998 SDG&E's average system rate cannot exceed
9.43 cents per kwh. Additional information on electric rates is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
Natural-Gas Rates The average price per therm of natural gas charged to customers was 65.0 cents in 1997 and 58.4 cents in 1996.
ENVIRONMENTAL MATTERS
Discussions about environmental issues affecting SDG&E, including electric and magnetic fields, hazardous substances, asbestos, air quality and water quality, are included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein. The following should be read in conjunction with those discussions.
Hazardous Substances In 1994 the CPUC approved the Hazardous Waste Collaborative Memorandum account, allowing utilities to recover 90 percent of certain costs to clean up hazardous waste contamination at past and present utility sites and to obtain recovery of some or all of such costs from responsible parties, and to recover 70 percent of the related insurance litigation expenses. SDG&E has asked the CPUC that, beginning on January 1, 1998, the electric-generation portion of the hazardous waste memorandum account be eliminated, and that the electric-generation-related cleanup costs be eligible for transition cost recovery. A CPUC decision is still pending. A discussion on transition costs and electric industry restructuring is included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 10 of the "Notes to Consolidated Financial Statements" herein.
Due to the fact that SDG&E disposes of its hazardous wastes at facilities owned and operated by other entities, applicable environmental laws may impose an obligation on SDG&E and others to undertake corrective actions if the owner or operator of such a facility fails to complete any required corrective actions. This type of obligation has been imposed upon SDG&E with respect to a site in Pico Rivera, California. SDG&E and 10 other entities have been named potential responsible parties by the California Department of Toxic Substances Control (DTSC) and are liable for any required corrective action regarding contamination at the site. DTSC has taken this action because SDG&E and others sold used electrical transformers to the site's owner. The DTSC considers SDG&E to be responsible for 7.4 percent of the transformer-related contamination at the site. The estimate for the development of the cleanup plan is $850,000. SDG&E has contributed $73,000 to the effort. The estimate for the actual cleanup, which commenced in 1997, is in the $2 million to $8 million range.
Underground Storage: California has enacted legislation to protect ground water from contamination by hazardous substances. Underground storage containers require permits, inspections and periodic reports, as well as specific requirements for new tanks, closure of old tanks and monitoring systems for all tanks. It is expected that cleanup of sites previously contaminated by underground tanks will occur for an unknown number of years. SDG&E cannot predict the cost of such cleanup. Pending assessment and remediation proceedings are described below.
In May 1987 the San Diego Regional Water Quality Control Board issued SDG&E a cleanup and abatement order for gasoline contamination originating from an underground storage tank located at SDG&E's Mountain Empire Operation and Maintenance facility. SDG&E assessed the extent of
the contamination, removed all contaminated soil and completed remediation of the site. Monitoring of the site confirms its remediation. SDG&E has applied for and is awaiting a site-closure letter from the Regional Water Quality Control Board.
Station B: Station B is located in downtown San Diego and was operated as a steam and electric-generating facility between 1911 and June 1993. Pursuant to a cleanup and abatement order, SDG&E remediated hydrocarbon contamination discovered as a result of the removal of three 100,000- gallon underground diesel-fuel storage tanks from an adjacent substation. SDG&E has applied for and is awaiting a site-closure letter from the San Diego County Department of Environmental Health.
OTHER
Research, Development and Demonstration (RD&D) SDG&E has been conducting RD&D in areas that provided value to SDG&E and its customers. Annual RD&D costs have averaged $6 million over the past three years. The CPUC historically has permitted rate recovery of these expenditures. In association with California's restructuring of the electric utility industry, the CPUC has established a new structure and initial funding levels to manage RD&D programs. A discussion of this is included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
Year 2000 Plans A discussion of Enova's plans to prepare the company's computer systems and applications for the year 2000 and beyond is included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
Wages SDG&E and Local 465, International Brotherhood of Electrical Workers have two labor agreements, a generation contract that runs through February 28, 1998 and a utility contract (transmission and distribution) that runs through August 31, 1998. Negotiations for a new generation contract are ongoing.
Employees of Registrant As of December 31, 1997 SDG&E had 3,576 employees, compared to 3,688 at December 31, 1996. Enova and its other consolidated subsidiaries had 89 employees at December 31, 1997 compared to 49 at December 31, 1997.
Foreign Operations SDG&E's foreign operations in 1997 included power purchases and sales with CFE in Mexico; purchases of natural gas from suppliers in Canada; and purchases of uranium from suppliers in Canada, Niger and Russia. Enova International is part of two consortia that are developing and operating natural-gas distribution systems in Mexico.
Additional information concerning foreign operations is provided under "Electric Operations," "Natural Gas Operations," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 9 of the "Notes to Consolidated Financial Statements" herein.
ITEM 2.
ITEM 2. PROPERTIES
Substantially all utility plant is subject to the lien of the July 1, 1940 mortgage and deed of trust and its supplemental indentures between
SDG&E and the First Trust of California N.A. as trustee, securing the outstanding first-mortgage bonds.
Information concerning SDG&E's properties is provided below. Additional information is provided under "Electric Operations," "Gas Operations," "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 2, 5, 9 and 10 of the "Notes to Consolidated Financial Statements" herein.
Electric Properties SDG&E's generating capacity is described in "Electric Resources", herein.
The 1997 system load factor was 55 percent and ranged from 55 percent to 64 percent for the past five years.
SDG&E's electric transmission and distribution facilities include substations, and overhead and underground lines. Periodically various areas of the service territory require expansion to handle customer growth.
SDG&E owns an approved nuclear power-plant site near Blythe, California.
Natural-Gas Properties SDG&E's natural-gas facilities are located in San Diego and Riverside counties and consist of the Moreno and Rainbow compressor stations, various high-pressure transmission pipelines, high-pressure distribution mains, and service lines. SDG&E's natural-gas system is sufficient to meet customer demand and short-term growth. SDG&E is currently undergoing an expansion of its high-pressure transmission lines to accommodate expected long-term customer growth.
Other SDG&E Properties The 21-story corporate office building at 101 Ash Street, San Diego is occupied pursuant to a capital lease through the year 2005. The lease has four separate five-year renewal options. SDG&E also occupies an office complex at Century Park Court in San Diego pursuant to an operating lease ending in the year 2007. The lease can be renewed for two five-year periods.
In addition, SDG&E occupies eight operating and maintenance centers, two business centers, six district offices, and five branch offices.
Non-Utility Property Phase One Development, a subsidiary of Pacific Diversified Capital, held one property in San Diego County during 1997. In December 1997 this property was sold for residential development.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
Management believes that the legal proceedings discussed below will not have a material adverse effect on Enova's results of operations, financial condition or liquidity.
Public Service Company of New Mexico On October 27, 1993 SDG&E filed a complaint with the FERC against Public Service Company of New Mexico, alleging that charges under a 1985 power- purchase agreement are unjust, unreasonable and discriminatory. SDG&E requested that the FERC investigate the rates charged under the agreement and establish December 26, 1993 as the effective refund
date. The relief, if granted, would reduce annual demand charges paid by SDG&E to PNM by up to $11 million per year through April 2001. If approved, the proceeds would be refunded principally to SDG&E customers.On December 8, 1993 PNM answered the complaint and moved that it be dismissed. PNM denied that the rates are unjust, unreasonable or discriminatory and asserted that SDG&E's claims were barred by certain orders issued by the FERC in 1988. On March 18, 1996 SDG&E filed a second complaint with FERC against PNM, alleging in part that applying the same methodology as SDG&E had used in the 1993 complaint, but based on more recent cost information, results in charges under the 1985 power purchase agreement that are unjust, unreasonable and discriminatory. SDG&E requested that the FERC investigate the rates charged under the 1985 agreement and establish May 17, 1996 as the effective refund date. The relief, if granted, would reduce annual demand charges paid by SDG&E to PNM, in addition to the amount from the first complaint, by up to $12 million per year. On April 26, 1996 PNM answered the second complaint and moved that it be dismissed for the same reasons in its answer to the 1993 complaint. On August 22, 1997 SDG&E filed a third complaint against PNM alleging that the demand rate paid by SDG&E under the PNM power- purchase agreement during 1996 was unjust and unreasonable, resulting in an overcharge of up to $9.6 million during this period. On September 29, 1997 PNM answered the third complaint and moved that it be dismissed for the same reasons stated in its answer to the 1993 complaint.
Canadian Natural Gas During early 1991 SDG&E signed four long-term natural gas supply contracts with Husky Oil Ltd., Canadian Hunter Ltd. and Noranda Inc., Bow Valley Energy Inc., and Summit Resources Ltd. Canadian-sourced natural gas began flowing to SDG&E under these contracts on November 1, 1993. Disputes have arisen with each of these producers with respect to events which are alleged by the producers to have occurred justifying a revision to the pricing terms of each contract, and possibly their termination. Consequently, during December 1993 SDG&E filed complaints in the United States Federal District Court, Southern District of California, seeking a declaration of SDG&E's contract rights. Specifically, SDG&E states that neither price revision nor contract termination is warranted.
On March 14, 1994 SDG&E voluntarily dismissed its complaint against Bow Valley without prejudice. On April 24, 1994 the court denied the other defendants' motions to dismiss SDG&E's complaints. These motions were based on jurisdictional grounds. Two of the defendants, Bow Valley and Husky Oil, filed claims on June 12, 1994 and June 29, 1994, respectively, against SDG&E with the Queen's Bench in Alberta, Canada, seeking a declaration that they are entitled to damages or, in the alternative, that they may terminate their respective contracts with SDG&E. SDG&E has answered these claims. On March 1, 1995 SDG&E and Husky Oil reached an agreement dismissing all of their respective claims with prejudice.
Bow Valley and Summit Resources gave SDG&E notice that their natural-gas supply contracts with SDG&E were terminated pursuant to provisions in the contract that purportedly give them the right to do so. SDG&E has responded that the notices were inappropriate and that it will seek both contract and tort damages. Bow Valley and Summit have subsequently ceased deliveries of natural gas to SDG&E.
On May 10, 1996 the U.S. District Court granted Canadian Hunter's and Summit's motions to dismiss the case, finding that the Alberta Sales of Goods Act rendered the gas-purchase agreements between SDG&E and the defendants voidable by either party. On June 1, 1996 Canadian Hunter
ceased deliveries of gas to SDG&E. On September 11, 1996 SDG&E filed in the Ninth Circuit Federal Court of Appeals an appeal of the U.S. District Court's judgment granting Canadian Hunter's and Summit's motions to dismiss the case.
On October 22, 1997 with respect to the Summit appeal and on December 31, 1997 with respect to the Canadian Hunter appeal, the Ninth Circuit Federal Court of Appeals held that the long-term contracts for SDG&E to buy Canadian natural gas were invalidated by changes in the Federal Energy Regulatory Commission's regulation of transportation rates and by a change in California's regulation of SDG&E gas rates. The Court upheld the U.S. District Court's order allowing both Summit and Canadian Hunter to void the 1991 gas-purchase agreements. The question of the value of the gas delivered remains before the U.S. District Court.
North City West On June 14, 1993 the Peninsula at Del Mar Highlands Homeowners Association filed a complaint with the Superior Court of San Diego County against the City of San Diego and SDG&E to prevent SDG&E from constructing and operating an electric substation in an area which is known as North City West. Construction was completed, and the substation became operational in June 1994. In the complaint, the plaintiffs sought to have the city either revoke previously issued permits or reopen the hearing process to address alleged electric and magnetic field concerns. On July 6, 1993 the court denied the plaintiffs' motion for a temporary restraining order. On July 30, 1993 the court denied the plaintiffs' motion for a preliminary injunction. On September 28, 1993 the plaintiffs withdrew their complaint and the court dismissed it without prejudice.
On August 18, 1993 the plaintiffs filed a complaint with the California Public Utilities Commission requesting that the CPUC conduct an environmental assessment. This complaint still is pending at the CPUC.
SONGS Personal Injury Litigation As previously discussed, SDG&E holds a 20-percent interest in the San Onofre Nuclear Generating Station. There have been seven radiation personal injury cases filed against various parties including Southern California Edison, SDG&E, Combustion Engineering, and the Institute of Nuclear Power Operations in Federal District Court, Southern District of California: James (filed July 12, 1994), McLandrich (February 6, 1995), Mettler (July 5, 1995), Knapp (August 31, 1995), Kennedy (November 17, 1995), Rock (November 28, 1995), and Keltsch (November 11, 1997). The plaintiffs allege their various types of leukemia or other forms of cancers were caused by radiation exposure from "fuel fleas" (radioactive fuel particles).
On October 12, 1995 the jury in the James case determined that there was no scientific link between the plaintiff's leukemia and the amount of radiation he was allegedly exposed to while employed at SONGS as an employee of a SONGS contractor. On August 15, 1996 the Ninth Circuit Court of Appeals upheld the decision. The time has lapsed for a petition for certiorari to the Supreme Court of the United States. Therefore, this matter is concluded.
McLandrich, Mettler and Knapp are wrongful death cases filed by the heirs of former SONGS employees seeking unspecified amounts in compensatory and punitive damages. Edison has been dismissed from McLandrich and Mettler based upon the District Court's ruling that Edison is an employer and workers' compensation is the exclusive remedy for the plaintiffs. The Ninth Circuit Court of Appeals rejected SDG&E's
petition for permission to challenge the lower court's determination that SDG&E is not an employer and thus may not avail itself of the workers' compensation exclusivity rule. McLandrich, Mettler and Knapp are stayed pending the outcome of a plaintiff's appeal in McLandrich, challenging the District Court's ruling that Southern California Edison can avail itself of the workers' compensation exclusivity rule.
The Kennedy and Rock cases involve family members of current or former SONGS employees who allege that the employees carried home fuel fleas which caused the family members' illnesses. The plaintiffs are alleging unspecified amounts of compensatory and punitive damages. Jury trial commenced in the Kennedy case on January 27, 1998 and is expected to last approximately six weeks. In the Keltsch case, no punitive damages are alleged. A motion to dismiss the case is scheduled to be heard on March 10, 1998. SDG&E has not been named in these actions; however, because of its ownership interest SDG&E may be adversely affected if plaintiffs are successful.
SONGS Pricing In May 1997 Ayad Rubaii, an employee of Edison, filed a complaint under the federal False Claims Act against Edison and SDG&E in United States District Court for the Southern District of California. The complaint was unsealed in July 1997 and sent to Edison and SDG&E on September 3, 1997. In the complaint, the plaintiff alleges that Edison and SDG&E have overcharged customers since early 1996 for energy produced at SONGS under a pricing mechanism approved by the CPUC and codified by the State Legislature. The plaintiff alleges that he filed the lawsuit on behalf of the United States Government. The Department of Justice has elected not to intervene in the lawsuit, but could elect to do so in the future if new information becomes available which, in its view, justifies intervention. The plaintiff is claiming damages of $383 million from Edison and $102 million from SDG&E. Under the False Claims Act, any damages are subject to trebling and penalties could be assessed. On November 7, 1997, SDG&E filed a motion to dismiss this complaint. A hearing before the U.S. District Court was held on January 20, 1998. The Court has not yet issued its decision on SDG&E's motion to dismiss.
Employee Benefits On September 16, 1997 two individual plaintiffs filed a complaint (Mascari v. SDG&E) in United States District Court for the Southern District of California on behalf of themselves and a purported class consisting of a significant number of temporary employees and independent contractors employed at SDG&E. Plaintiffs allege that they are and have been common law employees of SDG&E and, as such, under recent Ninth Circuit decisional law, are and have been entitled to participate in SDG&E's health and welfare, defined benefit and defined contribution plans. They seek to recover past and future benefits under each plan. On October 6, 1997 SDG&E filed its answer to the complaint, denying that the plaintiffs were or are entitled to any benefits and denying the appropriateness of a class.
Environmental and Regulatory Issues Other legal matters related to environmental and regulatory issues are described under "Environmental Matters," "Rate Regulation" and "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None.
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Enova Corporation
Common stock of Enova Corporation is traded on the New York and Pacific stock exchanges. At December 31, 1997 there were 72,639 holders of common stock. The quarterly common stock information required by Item 5 is included in the Enova Corporation schedule of Quarterly Financial Data herein.
San Diego Gas & Electric Company
All the common stock of San Diego Gas & Electric Company is owned by Enova Corporation and is not publicly traded. The following table sets forth the cash distributions on common stock paid to Enova Corporation by SDG&E:
First Quarter 45,479,582 Second Quarter 44,310,518 Third Quarter 44,310,518 Fourth Quarter 44,322,572
In addition, in March 1997 SDG&E paid Enova a special dividend of $70,000,000 to be used for the repurchase of 3 million shares of Enova Corporation common stock.
Dividend Restrictions
The CPUC regulates SDG&E's capital structure, limiting the dividends it may pay to Enova. At December 31, 1997 $152 million of common equity was available for future dividends. In addition, at December 31, 1997 approximately one half of the $658 million of rate-reduction bonds was also available for future dividends. Of this available amount, $100 million in dividends was paid by SDG&E to Enova on January 2, 1998, in conjunction with the acquisition of Sempra Energy Trading.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
Enova Corporation
*Includes long-term debt redeemable within one year.
This summary should be read in conjunction with the Enova Corporation consolidated financial statements and notes to consolidated financial statements.
ITEM 6. SELECTED FINANCIAL DATA
San Diego Gas & Electric Company
*Includes long-term debt redeemable within one year.
This summary should be read in conjunction with the San Diego Gas & Electric Company consolidated financial statements and notes to consolidated financial statements.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- Enova Corporation/San Diego Gas & Electric Company
GENERAL Enova Corporation (referred to herein as Enova, which includes the parent and its wholly owned subsidiaries) was formed in January 1996 to become the parent company of San Diego Gas & Electric (SDG&E). At that time SDG&E's outstanding common stock was converted on a share-for-share basis into Enova Corporation common stock. SDG&E's debt securities, preferred stock and preference stock were unaffected and remained with SDG&E. 	 SDG&E is an operating public utility engaged in the electric and gas businesses. It generates and purchases electric energy and distributes it to 1.2 million customers in San Diego County and an adjacent portion of Orange County, California. It also purchases and distributes natural gas to 721,000 customers in San Diego County and transports electricity and gas for others. California has enacted an electric-restructuring law that affects the operations of SDG&E and the other California investor-owned electric utilities. This information is discussed below under "Electric Industry Restructuring." Enova has several other subsidiaries (referred to herein as nonutility subsidiaries). Enova Financial invests in limited partnerships representing approximately 1,200 affordable-housing properties located throughout the United States. Califia leases computer equipment. These two subsidiaries are expected to provide income tax benefits over the next several years. Enova International is involved in energy projects outside the United States. Pacific Diversified Capital is the parent company of Phase One Development, which has been involved in real estate development. Enova Energy is an energy management and consulting firm offering services to utilities and large consumers. In December 1997, subsidiaries of Enova Energy and Houston Industries formed a joint venture, El Dorado Energy, to build, own and operate a natural gas-fired power plant in Boulder City, Nevada. Enova Technologies is in the business of developing new technologies generally related to utilities and energy. In January 1997, Enova Energy, Enova Technologies and certain subsidiaries of Pacific Enterprises (discussed below) formed Energy Pacific, a joint venture to market integrated energy and energy- related products and services. Energy Pacific has recently changed its name to Sempra Energy Solutions. In January 1998, Sempra Energy Solutions completed the acquisition of CES/Way International, a leading national energy-service provider. In December 1997, Enova and Pacific Enterprises completed the joint acquisition of AIG Trading Corporation (AIG), a leading natural gas and power marketing firm based in Greenwich, Connecticut. AIG has subsequently changed its name to Sempra Energy Trading. Additional information regarding Enova's nonutility subsidiaries is described herein under "Electric Generation" and "Liquidity and Capital Resources - Investing Activities," and in Notes 1, 2 and 3 of the notes to consolidated financial statements.
BUSINESS COMBINATION In October 1996, Enova and Pacific Enterprises (PE), parent company of Southern California Gas Company (SoCalGas), announced that they have agreed to combine the two companies. Enova and PE have selected Sempra Energy as the name of the new company formed by the business combination. As a result of the combination, which was unanimously approved by the boards of directors of both companies, (i) each outstanding share of common stock of Enova will be converted into one share of common stock of Sempra Energy, (ii) each outstanding share of common stock of PE will be converted into 1.5038 shares of Sempra Energy's common stock and (iii) the preferred stock and preference stock
of SDG&E, PE and SoCalGas will remain outstanding. In March 1997, the shareholders of Enova and PE approved the combination. Consummation of the combination is conditional upon the approvals of the California Public Utilities Commission (CPUC) and various other regulatory bodies (see below). 	 In June 1997, the CPUC revised its procedural schedule for the business combination after delaying until July 1997 its final decision on the Performance-Based Ratemaking (PBR) proceeding for SoCalGas. (The CPUC's decision on SoCalGas' PBR proceeding adopted a rate-setting mechanism for SoCalGas that provides incentives for cost control and efficiency improvement, including comparisons of productivity and other factors against benchmarks based on industry performance. SoCalGas had been operating under traditional "cost of service" regulation. The decision provides for, among other things, a net rate reduction of $160 million.) In accordance with the CPUC's revised schedule, the administrative law judge handling the proceeding issued a draft decision on February 23, 1998. That draft decision proposed approval of the combination. Among other things, the draft decision proposed 50/50 sharing of the net cost savings resulting from the combination between shareholders and customers, but only for five years rather than the 10 years sought. The draft decision would reduce the net shareholder savings from $1.1 billion to $340 million. The CPUC decision is scheduled for the end of March 1998. 	 In November 1997, the California attorney general issued an advisory opinion concluding that the business combination would not adversely affect competition within either the wholesale electricity or interstate gas markets. The opinion included a recommendation that the CPUC consider requiring SoCalGas to auction offsetting volumes of natural gas transportation rights equal to the load with SDG&E that will be withdrawn if the CPUC concludes that SDG&E would be eliminated as a potential competitor in the partially regulated intrastate gas transmission market. 	In September 1997, the CPUC staff issued a final Negative Declaration, concluding that the business combination will not result in any activities or operational changes that may cause a significant adverse effect on the environment. In June 1997, the Federal Energy Regulatory Commission (FERC) approved the business combination, subject to the conditions that the combined company will not unfairly use any potential market power regarding natural gas transportation to gas-fired electric-generation plants. The FERC acknowledged that this issue is clearly within the jurisdiction of the CPUC and the conditions will be considered during the CPUC review process. Therefore, the FERC's final decision is not expected to be issued before the CPUC's approval. 	 In August 1997, the Nuclear Regulatory Commission approved the business combination, ruling that the creation of the new company will not affect SDG&E's qualifications to hold the license for its 20-percent interest in the San Onofre Nuclear Generating Station (SONGS). 	Remaining regulatory reviews, which are not expected to be concluded prior to the CPUC decision, include clearance by the U.S. Department of Justice, under the Hart-Scott-Rodino Antitrust Act, and approval by the Securities and Exchange Commission. Both agencies will review the business combination for its impacts on competition. 	The commencement of combined operations is expected in the summer of 1998. Earnings of the combined company could be negatively impacted in 1998, and to a lesser extent in subsequent years, by delays in achieving cost savings from the combination caused by the later-than- expected effective combination date, CPUC limitations on transactions between SDG&E and SoCalGas, which may be modified by the CPUC combination proceedings (discussed below), the possibility that the CPUC
might not permit recovery of certain costs of the combination and might reduce the period or percentage for shareholder participation in the related cost savings, and slower-than-anticipated growth in revenues from Sempra Energy Solutions. Additional information regarding the proposed business combination is described in Note 1 of the notes to consolidated financial statements.
RESULTS OF OPERATIONS Operating Results	 Electric revenues increased 11 percent in 1997, primarily due to an increase in sales for resale to other utilities and increased retail sales volume due to weather. Electric revenues increased 6 percent in 1996, primarily due to the accelerated recovery of SONGS Units 2 and 3 which commenced in April 1996. Gas revenues increased 14 percent in 1997, primarily due to weather-related higher sales volume and higher purchased-gas prices, offset by an increase in customer purchases of gas directly from other suppliers (for whom SDG&E provides transportation). Gas revenues increased 12 percent in 1996, reflecting higher purchased-gas prices. 	 Operating Expenses Electric fuel expense increased 22 percent in 1997, primarily due to increased natural gas prices and increased natural gas- fired generation resulting from SONGS Units 2 and 3 refuelings. Electric fuel expense increased 34 percent in 1996, primarily due to increased generation and increases in natural gas prices. Purchased-power expenses increased 42 percent in 1997, primarily due to increased volume, which resulted from lower nuclear-generation availability from the SONGS refuelings and increased use of purchased power due to decreased purchased-power prices. Purchased-power expenses decreased 9 percent in 1996, reflecting the availability of lower-cost nuclear generation and decreases in purchased-power capacity charges. Gas purchased for resale increased 20 percent in 1997 and 34 percent in 1996, primarily due to increases in sales volume and in natural gas prices. The changes in maintenance expenses reflect the nuclear refuelings in 1997 and 1995. General and administrative expenses decreased 15 percent in 1997, primarily due to higher 1996 costs for customer service, partially offset by the expenses relating to the proposed business combination with Pacific Enterprises.
Earnings 1997 earnings per common share were $2.20 compared to $1.98 in 1996 and $1.94 in 1995. The increase in earnings in 1997 is primarily due to incentive rewards for Performance-Based Ratemaking (PBR) and Demand-Side Management (DSM) programs, retirements of debt and common shares, and improved earnings of Enova Financial, partially offset by expenses relating to the proposed business combination with Pacific Enterprises. Other events that improved 1997 earnings included income tax benefits from the 1995 sale of Wahlco Environmental Systems and capital gains from the sale of property held by Pacific Diversified Capital. The increase in earnings in 1996 is primarily due to DSM rewards, partially offset by SDG&E's lower authorized return on equity. Earnings per share for the quarter ended December 31, 1997, were $0.72, compared to $0.47 for the same period in 1996. The increase in earnings for the quarter was due to numerous offsetting factors, including PBR and DSM rewards, retirement of common shares, higher off- system electric sales, previously announced seasonal variability related to the elimination of electric balancing accounts, and expenses relating to the proposed business combination with Pacific Enterprises. Although the elimination of the balancing accounts did not have any effect on 1997 full-year earnings, quarterly earnings now fluctuate significantly, depending on monthly or seasonal changes in electric sales and fuel
prices. In general, earnings are expected to be higher in high sales- volume months and lower in others. In 1998 and future years, full-year earnings also will be affected by sales volumes. Some of the PBR rewards recorded in 1997 had been pending with the CPUC for several years. During 1998, SDG&E will not have a multiple-year backlog of these PBR rewards to record. In addition, because of the elimination of the Generation and Dispatch PBR mechanism and the San Onofre Nuclear Generating Station Target Capacity Factor mechanism, the impact of performance rewards on future earnings will be reduced. Califia and Enova Financial's contributions to earnings for the year were $0.21 in 1997, $0.19 in 1996 and $0.17 in 1995. Contributions to earnings by Enova Energy and Enova Technologies were negatively impacted in 1997 by the slower-than-anticipated growth in revenues from Sempra Energy Solutions.
LIQUIDITY AND CAPITAL RESOURCES SDG&E's operations continue to be a major source of liquidity. In addition, financing needs are met primarily through issuances of short- term and long-term debt. These capital resources are expected to remain available. Cash requirements include utility capital expenditures, nonutility subsidiaries' investments, and repayments and retirements of long-term debt. Nonutility cash requirements include capital expenditures associated with subsidiary activities related to the plans to distribute natural gas in Mexico and the eastern United States; new products; investments in Sempra Energy Trading, CES/Way International and El Dorado Energy; and affordable-housing, leasing and other investments. Additional information on these activities is discussed under "Cash Flows from Investing Activities" below. In addition to changes described elsewhere, major changes in cash flows are described below.
Cash Flows from Operating Activities The major changes in cash flows from operations among the three years result from changes in income taxes, accounts receivable, other current assets, accounts payable, and regulatory balancing accounts. The changes in cash flows related to income taxes were primarily due to the timing of certain deductions in 1997 and higher 1996 income tax payments in connection with settlements with the Internal Revenue Service. The changes in cash flows related to accounts and notes receivable were primarily due to increases in sales in December 1997. The changes in cash flows related to other current assets were primarily due to advances made to unconsolidated subsidiaries during late 1997. The changes in cash flows related to accounts payable were primarily due to fluctuations in natural gas purchases and prices from year to year. The changes in cash flows related to regulatory balancing accounts were primarily due to overcollections in the Electric Revenue Adjustment Mechanism (ERAM) account as a result of higher-than-authorized sales volumes in 1997 and changes in prices for natural gas in 1996. Quarterly cash dividends of $0.39 per share were declared for the year ended December 31, 1997. The dividend payout ratios for the years ended December 31, 1997, 1996, 1995, 1994 and 1993 were 71 percent, 79 percent, 80 percent, 130 percent, and 82 percent, respectively. The increase in the payout ratio for the year ended December 31, 1994, was due to writedowns recorded during 1994. For additional information regarding the writedowns, see Enova Corporation's 1996 Annual Report. The payment of future dividends is within the discretion of the Enova Board of Directors and is dependent upon future business conditions, earnings and other factors. Net cash flows provided by operating activities currently are sufficient to maintain the payment of dividends at the present level.
Enova has initiated an enterprise-wide program to prepare the company's computer systems and applications for the year 2000 and beyond. A comprehensive review has been conducted to identify the systems that could be affected by the year 2000 issue and an implementation plan has been developed. The year 2000 issue results from time-sensitive software applications that recognize a date using only two digits. For example, "00" may be recognized as the year 1900 rather than the year 2000. This could result in a system failure or miscalculations. This year 2000 problem creates risk for the company from unforeseen problems in its own computer systems and from third parties with whom the company deals on financial transactions. Management has not yet assessed whether the company's date-conversion project will be completed on a timely basis nor the impact of third- party computer system failures. The company expects to incur internal staff costs as well as consulting and other expenses related to infrastructure and facilities enhancements necessary to prepare the systems for the year 2000. Expenditures for the testing and conversion of system applications were $4 million in 1997 and are expected to be between $20 million and $25 million over the next two years. These costs are expensed as incurred.
Cash Flows from Financing Activities Enova did not issue additional stock or long-term debt in 1997, except for SDG&E-related refinancings and electric industry restructuring-related rate-reduction bonds. Additional information concerning the rate-reduction bonds is discussed below and under "Electric Industry Restructuring." Enova and SDG&E do not plan any issuances in 1998. In October 1997, SDG&E issued $25 million of tax-exempt Industrial Development Bonds (IDBs) through the City of Chula Vista. The variable- rate bonds were issued at an initial rate of 3.5 percent. The proceeds from the bonds, which will mature in 2023, were used to redeem $25 million of 8.75 percent IDBs with the City of San Diego. Also during 1997, SDG&E purchased and retired $62 million of 9.625 percent and 8.5 percent first mortgage bonds. In December 1997, $658 million of rate-reduction bonds were issued on SDG&E's behalf at an average interest rate of 6.26 percent. A portion of the bond proceeds was used to retire $14.9 million of variable-rate, taxable IDBs in December 1997 and $15.7 million of variable-rate, taxable IDBs in January 1998. Additional retirements are planned. Additional information concerning the rate-reduction bonds is provided below under "Electric Industry Restructuring." SDG&E currently has approximately $83 million of temporary investments that will be maintained into the future. The purpose of maintaining such a level of investments is to offset a like amount of long-term debt. The specific debt series being offset consists of variable-rate IDBs. The CPUC has approved specific ratemaking treatment which allows SDG&E to offset IDBs as long as there is at least a like amount of temporary investments. If and when SDG&E requires all or a portion of the $83 million of IDBs to meet future needs for long-term debt, such as to finance new construction, the amount of investments which is being maintained will be reduced below $83 million and the level of IDBs being offset will be reduced by the same amount. During 1997, Enova Corporation repurchased three million shares of its outstanding common stock. During 1998, the $1.82-series preferred stock becomes callable at $26 per share. SDG&E maintains its capital structure so as to obtain long-term financing at the lowest possible rates. The following table shows the percentages of capital represented by the various components. In 1993 the capital structure is net of the construction funds held by a trustee.
1993 1994 1995 1996 1997 Goal ----------- (A) (B) (A) - ------------------------------------------------------------------------ Common equity 47 % 48 % 49 % 50 % 51 % 41 % 46-49 % Preferred stock 4 4 4 4 4 3 3-5 Debt and leases 49 48 47 46 45 56 46-49 - ------------------------------------------------------------------------ Total 100 % 100 % 100 % 100 % 100 % 100 % 100 % - ------------------------------------------------------------------------ (A) Excludes rate reduction bonds ($658 million at December 31, 1997). (B) Includes rate reduction bonds ($658 million at December 31, 1997).
The CPUC regulates SDG&E's capital structure, limiting the dividends it may pay Enova. At December 31, 1997, $152 million of common equity was available for future dividends. In addition, at December 31, 1997, approximately one half of the $658 million of rate-reduction bonds was also available for future dividends. Of this available amount, $100 million in dividends were paid by SDG&E to Enova on January 2, 1998, in conjunction with the acquisition of Sempra Energy Trading. This restriction is not expected to affect Enova's ability to meet its cash obligations. In December 1997, Moody's Investors Service upgraded SDG&E's long- term-bond rating from an A1/stable outlook to an A1/positive outlook, reflecting SDG&E's business mix, which is heavily weighted toward distribution and transmission. The outlook upgrade also reflects the probability of recovery of stranded costs and the expected proceeds from the sale of generating assets (see discussion under "Electric Generation"). Standard & Poor's Ratings Group affirmed SDG&E's long- term-bond rating of A+/positive outlook.
Cash Flows from Investing Activities Cash used in investing activities in 1997 included SDG&E's construction expenditures and payments to its nuclear decommissioning trusts. SDG&E's capital expenditures were $197 million in 1997 and are estimated to be $242 million in 1998. Actual capital expenditures in 1997 were lower than anticipated due to changes in the scope and timing of several major capital projects. Estimated 1998 capital expenditures are closer to normal levels, with increases to meet industry restructuring needs and improvements to the electric distribution system. SDG&E continuously reviews its construction, investment and financing programs and revises them in response to changes in competition, customer growth, inflation, customer rates, the cost of capital, and environmental and regulatory requirements. Among other things, the level of expenditures in the next few years will depend heavily on the impacts of industry restructuring and the sale of SDG&E's Encina and South Bay power plants and other electric-generating assets, as well as the timing and extent of expenditures to comply with air-emission reduction and other environmental requirements. Additional information concerning the proposed sale of SDG&E's electric-generating assets is provided below under "Electric Generation." Payments to the nuclear-decommissioning trusts are expected to continue until SONGS is decommissioned, which is not expected to occur before 2013. Although Unit 1 was permanently shut down in 1992, it is scheduled to be decommissioned concurrently with Units 2 and 3. However, this will depend on the outcome of the proposed sale of SDG&E's electric-generating assets, including its interest in SONGS. Enova's level of nonutility expenditures in the next few years will depend primarily on the activities of its subsidiaries other than SDG&E, including Sempra Energy Solutions and the natural gas distribution projects in Mexico and the eastern United States. Nonutility expenditures were $158 million in 1997 and are estimated to be $100
million in 1998, not including special projects. The decrease in expected expenditures in 1998 is primarily attributable to a decrease in expected investments by Enova Financial. As discussed previously, in January 1997, certain subsidiaries of Enova and Pacific Enterprises formed Sempra Energy Solutions, a joint venture to market integrated energy and energy-related products and services. During 1997, Enova invested $21 million in Sempra Energy Solutions. In addition, in January 1998, Sempra Energy Solutions completed the acquisition of CES/Way International, a leading national energy-service provider. In September 1997, Sempra Energy Solutions formed a joint venture with Bangor Hydro to build, own and operate a $40 million natural gas distribution system in Bangor, Maine. In addition, in December 1997 Sempra Energy Solutions signed a partnership agreement with Frontier Utilities to build and operate a $55 million natural gas distribution system in North Carolina. In December 1997, Enova and Pacific Enterprises completed the joint acquisition of AIG Trading Corporation, a leading natural gas and power marketing firm. Enova contributed $110.6 million to that acquisition, which was subsequently renamed Sempra Energy Trading. In July 1997, Enova International and its partners, Pacific Enterprises International and Proxima S.A. de C.V., delivered their first supply of natural gas to Baja California. The Mexican company formed by the three partners, Distribuidora de Gas Natural de Mexicali, will invest up to $25 million during the first five years of the 30-year license period to supply natural gas to the region. The partnership is expected to serve 25,000 customers over the next four years. In March 1997, the Mexican Energy Regulatory Commission awarded the partners their second natural gas privatization license in Mexico, allowing Distribuidora de Gas Natural de Chihuahua to build and operate a natural gas distribution system in Chihuahua. That partnership plans to invest approximately $50 million in the project and is expected to serve 50,000 customers over the next five years. In January 1998, Enova International and its partner, Union Fenosa ACEX of Spain, submitted a bid to build, own and operate a natural gas distribution system in Monterrey, Mexico. The project will consist of an initial investment of $190 million for a system that will serve 320,000 customers, with an additional $60 million invested over five years to serve a total of 400,000 customers. Two other international consortia have submitted bids on the project. The Mexican Energy Regulatory Commission is expected to announce the winning bidder in March 1998. In December 1997, Enova Power Corporation, a subsidiary of Enova Energy, and Houston Industries Power Generation formed El Dorado Energy, a joint venture to build, own and operate a natural gas power plant in Boulder City, Nevada. Enova invested $2.3 million in El Dorado Energy in 1997 and expects to invest an additional $37 million in 1998 and $17 million in 1999. Additional information about these acquisitions and joint ventures is discussed in Note 3 of the notes to consolidated financial statements.
Derivative Financial Instruments The policy of Enova is to use derivative financial instruments to reduce exposure to fluctuations in interest rates, foreign currency exchange rates and natural gas prices. These financial instruments are with major investment firms and expose Enova to market and credit risks. At times, these risks may be concentrated with certain counterparties, although counterparty nonperformance is not anticipated. SDG&E periodically enters into interest-rate swap and cap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowing. These swap and cap agreements generally
remain off the balance sheet as they involve the exchange of fixed- and variable-rate interest payments without the exchange of the underlying principal amounts. The related gains or losses are reflected in the income statement as part of interest expense. SDG&E would be exposed to interest-rate fluctuations on the underlying debt should other parties to the agreement not perform. Such nonperformance is not anticipated. At December 31, 1997, SDG&E had an agreement for a floating-to-fixed-rate swap associated with $45 million of variable-rate bonds maturing in 2002. SDG&E's pension fund periodically uses foreign-currency forward contracts to reduce its exposure to exchange-rate fluctuations associated with certain investments in foreign equity securities. These contracts generally have maturities ranging from three to six months. At December 31, 1997, and 1996, there were no foreign-currency forward contracts outstanding. In November 1996, SDG&E commenced price risk management activities, on a limited basis, in the area of hedging price volatility of natural gas requirements. SDG&E uses energy derivatives for both hedging and trading purposes within certain limitations imposed by company policies. These derivative financial instruments include forward contracts, swaps, options and other contracts which have maturities ranging from 30 days to nine months. Additional information on derivative financial instruments of SDG&E is provided in Note 8 of the notes to consolidated financial statements and under "Market Risk" below. Sempra Energy Trading Corp. derives a substantial portion of its revenue from trading activities in natural gas, petroleum and electricity. Trading profits are earned as Sempra Energy Trading acts as a dealer in structuring and executing transactions that permit its counterparties to manage their risk profiles. In addition, Sempra Energy Trading takes positions in energy markets based on the expectations of future market conditions. These positions may be offset with similar positions or may be offset in the exchange traded markets. These positions include options, forwards, futures and swaps. Additional information on derivative financial instruments of Sempra Energy Trading is provided in Note 3 of the notes to consolidated financial statements and under "Market Risk" below.
Market Risk Market risk arises from the potential change in the value of financial instruments and physical commodities based on fluctuations in natural gas, petroleum and electricity commodity exchange prices and basis. Market risk is also affected by changes in volatility and liquidity in markets in which these instruments are traded. SDG&E utilizes a variety of financial structures, products and terms which require the company to manage, on a portfolio basis, the resulting market risks inherent in these transactions, subject to parameters established by company policies. Market risks are monitored separately from the groups that create or actively manage these risk exposures to ensure compliance with the company's stated risk management policies at both the Enova and subsidiary levels. SDG&E measures the risk in its portfolio on a daily basis in accordance with value-at-risk methodologies, which simulate forward price curves in the energy markets to estimate the size and probability of future potential losses. The quantification of market risk using value-at-risk provides a consistent measure of risk across diverse energy markets and products. The use of this methodology requires a number of key assumptions, including the selection of a confidence level for losses and the holding period chosen for the value-at-risk calculation. SDG&E expresses value-at-risk as the amount of SDG&E's earnings at risk based on a 95 percent confidence level using a time horizon of the average life of the portfolio. As of December 31, 1997, SDG&E's value-
at-risk for its price-risk management activities was $2.8 million (net of income taxes) of SDG&E's net earnings. Since this is not an absolute measure of risk under all conditions for all products, SDG&E performs alternative scenario analyses to estimate the economic impact of a sudden market movement on the value of the portfolio. This and the professional judgment of experienced business and risk managers is used to supplement the value-at-risk methodology. Based upon the ongoing policies and controls discussed above, SDG&E does not anticipate a material adverse effect on its financial position or results of operations as a result of market fluctuations. A Risk Management Committee, composed of Enova and Pacific Enterprises officers, is responsible for monitoring operating performance and compliance with established risk management policies for Sempra Energy Solutions and its subsidiaries. Sempra Energy Trading has established position and stop-loss limits for each line of business to monitor its market risk and traders are required to maintain positions within these market-risk limits. The position limits are monitored during the day by Sempra Energy Trading's senior management, which determines whether to adjust its market-risk profile. All of Sempra Energy Trading's market-risk sensitive instruments are entered into for trading purposes. The following table provides the potential changes in net principal transaction revenues resulting from hypothetical 10-percent increases and 10-percent decreases in the applicable commodity prices for significant commodity market-price sensitive instruments held on December 31, 1997. This quantitative information about market risk is limited because it does not take into account potential hedging transactions or changes to the market-risk profile of the portfolio by management in reaction to such changes in market conditions. Additionally, it does not take into account anticipated management reaction to breaches of counterparty credit limitations caused by the shocks within a given risk category. Further, inherent limitations arise from assuming that hypothetical 10-percent increases and 10-percent decreases in commodity prices move in the same direction, and this information does not recognize co-movements in prices. The following table presents the impact on Sempra Energy Trading's net principal transaction revenues resulting from a 10-percent increase and a 10-percent decrease in the respective December 31, 1997 commodity prices:
In thousands of dollars - ----------------------------------------------------------------------- Commodity 10% Increase 10% Decrease - ----------------------------------------------------------------------- Crude oil and derivatives $ 3,288	 $ (3,288) Natural gas (2,441) 2,441 Emission credits (81) 81 Electricity (540) 540 - -----------------------------------------------------------------------
SDG&E's payments to the externally managed nuclear decommissioning trust funds expose SDG&E to market risk. Market risk can result from fluctuations in the volatility and liquidity in markets in which these instruments are traded. These fluctuations can also correspondingly affect the level of funding of the decommissioning trust.
Credit Risk Credit risk relates to the risk of loss that would be incurred as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. SDG&E and Sempra Energy Trading avoid concentration of counterparties and maintain credit policies with regard to counterparties that management believes significantly minimize
overall credit risk. These policies include an evaluation of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances, and the use of standardized agreements which allow for the netting of positive and negative exposures associated with a single counterparty. The companies monitor credit risk exposure through an approval process and the assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry.
ELECTRIC INDUSTRY RESTRUCTURING Background In September 1996, the state of California enacted a law restructuring California's electric utility industry (AB 1890). The legislation adopts the December 1995 CPUC policy decision that restructures the industry to stimulate competition and reduce rates. In May 1997, the CPUC issued a decision providing for direct access to be available to all California electric customers on January 1, 1998. The CPUC concluded that there were no technical or operational barriers to justify limiting direct access availability once electric restructuring commenced. The decision allowed customers to begin choosing electricity providers in November 1997. In December 1997, the CPUC agreed to delay the initiation of electric restructuring until March 31, 1998, to allow California's Power Exchange (PX) and Independent System Operator (ISO) to resolve computer software problems and conduct additional user training. Beginning on March 31, 1998, customers will be given the choice to continue to purchase electricity from their local utility under regulated tariffs, to enter into contracts with other energy service providers (i.e., private generators, brokers, etc.) or buy their power from the independent PX that serves as a wholesale power pool allowing all energy producers to participate competitively. The PX obtains power from qualifying facilities, nuclear units and, lastly, from the lowest-bidding suppliers. The ISO will schedule the power transactions and access to the transmission system. To facilitate this, the utilities will transfer the operational control of their transmission facilities to the ISO. The local utility will continue to provide distribution services, regardless of which source the consumer chooses. These customer choices will, in effect, open up the service territories of all California utilities. This will allow Enova, through Sempra Energy Solutions, to pursue customers outside of SDG&E's traditional service territory to provide electricity and other energy-related services. This also allows other energy-service providers to enter SDG&E's service territory to compete for generation customers. 	 Transition Costs Both the CPUC decision and the California legislation allow utilities, within certain limits, the opportunity to recover their stranded costs incurred for certain above-market CPUC-approved facilities, contracts and obligations through the establishment of a nonbypassable competition transition charge (CTC). The CPUC's direction is that traditional cost-of-service regulation will move toward performance-based regulation. Utilities are allowed a reasonable opportunity to recover their stranded costs through December 31, 2001. Stranded costs such as reasonable employee-related costs directly caused by restructuring and purchased-power contracts (including those with qualifying facilities) may be recovered beyond 2001, subject to a reasonableness review. SDG&E's transition-cost application, filed in October 1996, identified $2 billion of estimated stranded costs, including generation, purchased-power and qualifying facilities' contracts, and regulatory assets. The amount includes sunk costs, as well as ongoing costs the CPUC finds necessary to maintain generation facilities through December 31, 2001. These identified transition costs were determined to be
reasonable by independent auditors selected by the CPUC, with $73 million identified as requiring further action before being deemed recoverable transition costs. Through December 31, 1997, SDG&E has recovered transition costs of $0.2 billion for nuclear generation and $0.1 billion for nonnuclear generation. Additionally, overcollections of $0.1 billion recorded in the Energy Cost Adjustment Clause (ECAC) and the Electric Revenue Adjustment Mechanism (ERAM) balancing accounts as of December 31, 1997, have been applied to transition cost recovery, leaving approximately $1.6 billion for future CTC recovery. Included therein is $0.4 billion for post-2001 purchased-power-contract payments that may be recovered after 2001, subject to an annual reasonableness review. Outside of the exceptions discussed above, transition costs not recovered by December 31, 2001, will not be collected from customers. Such costs, if any, would be written off as a charge against earnings. AB 1890 clarifies that all existing and future consumers must pay CTC, except for a segment of self-generators and irrigation districts. SDG&E has very few, if any, of these types of customers and does not anticipate a material impact from the exemption. During the 1998-2001 period, the recovery of transition costs is limited by the rate freeze (discussed below). Management believes that the rates within the rate freeze and the proceeds from the sale of electric-generating assets (discussed below) will be sufficient to recover all of SDG&E's approved transition costs by December 31, 2001. In November 1997, the CPUC issued a decision allowing SDG&E the opportunity to recover all of its sunk nonnuclear generation costs, with the exception of $39 million in fixed costs relating to gas transportation to power plants, which SDG&E believes will be recovered through contracts with the ISO. The decision does not include generation plant additions made after December 20, 1995. Instead, SDG&E must file an application seeking a CPUC reasonableness review thereof. In October 1997, SDG&E filed an application with the CPUC seeking recovery of $14.5 million in 1996 capital additions for the Encina and South Bay power plants. A final CPUC decision is expected in 1998.
Rate-Reduction Bonds AB 1890 required a 10-percent rate reduction for residential and small-commercial customers beginning in January 1998. AB 1890 also provided for the issuance of rate-reduction bonds by an agency of the state of California to enable California's investor-owned electric utilities (IOUs) to use the proceeds to finance this rate reduction. In December 1997, $658 million of rate-reduction bonds were issued on behalf of SDG&E at an average interest rate of 6.26 percent. These bonds are being repaid over 10 years by SDG&E's residential and small-commercial customers via a nonbypassable charge on their electricity bills. In September 1997, SDG&E and the other California IOUs received a favorable ruling by the Internal Revenue Service on the tax treatment of the bond transaction. The ruling states, among other things, that the receipt of the bond proceeds does not result in gross income to SDG&E at the time of issuance, but rather the proceeds are taxable over the life of the bonds. The Securities and Exchange Commission determined that these bonds should be reflected on the utilities' balance sheets as debt, even though the bonds are not secured by, or payable from, utility assets, but rather by the revenue streams collected from customers. SDG&E formed a subsidiary, SDG&E Funding LLC, to facilitate the issuance of the rate-reduction bonds. In exchange for the bond proceeds, SDG&E sold to SDG&E Funding all of its rights to the revenue streams. Consequently, the revenue streams are not the property of SDG&E nor are they available to satisfy any claims of SDG&E's creditors. There was no gain or loss recorded from the issuance of the bonds or the receipt of the proceeds. SDG&E has begun to use a portion of the proceeds to redeem its higher cost debt, described herein under "Liquidity and Capital Resources - Financing Activities." In December
1997, the California Supreme Court dismissed a petition submitted by a coalition of consumer groups to overturn the CPUC's Rate-Reduction Bond financing orders. A related coalition of consumer groups has also put together a California ballot initiative that, among other things, would possibly result in an additional 10-percent rate reduction, require that this rate reduction be achieved through the elimination or reduction of CTC payments and prohibit the collection of the charge on customer bills that would finance the rate reduction. SDG&E cannot predict the final outcome of the initiative. If the initiative were to be voted into law and upheld by the courts, the financial impact on SDG&E could be substantial.
Electric Rates AB 1890 included a rate freeze for all customers. Until the earlier of March 31, 2002, or when transition cost recovery is complete, SDG&E's average system rate will be frozen at 9.64 cents per kilowatt-hour, except for the impacts of natural gas price changes and the mandatory 10-percent rate reduction. As a result of significant increases in natural gas prices during the first quarter of 1997, SDG&E received CPUC authority to increase rates, but rates could not be increased above 9.985 cents per kwh. With the 10-percent rate reduction beginning on January 1, 1998, the maximum system-average rate became 9.43 cents per kwh. SDG&E's ability to recover its transition costs is dependent on its total revenues under the rate freeze exceeding normal cost-of-service revenues during the transition period by at least the amount of the CTC less any proceeds from the sale of electric-generating assets (discussed below). During the transition period, SDG&E will not earn awards from special programs, such as DSM, unless total revenues are also adequate to cover the awards. Fuel-price volatility is the most significant variable in the ability of SDG&E to recover its transition costs and program awards.
Balancing Accounts In October 1997, the CPUC issued a decision eliminating the ECAC and the ERAM balancing accounts, effective December 31, 1997. As of December 31, 1997, net overcollections for these accounts of $130 million have been transferred to the interim transition-cost-balancing account to be applied to CTC recovery, subject to a reasonableness review. The decision eliminates further ECAC proceedings for generation costs incurred beginning in January 1998. Additionally, the decision eliminates all other electric balancing accounts, except for those associated with the administration of DSM, low-income assistance, and research and development (R&D) programs, which will be used to assist in the administration of public-purpose funds (discussed below). In addition, SDG&E has requested the retention of the Electric Vehicle balancing account through December 31, 1998. The elimination of ERAM and ECAC resulted in earnings volatility that began in the first quarter of 1997. Although no effect in 1997 was seen for the full year, quarterly earnings fluctuated significantly, as was the case for the other California IOUs. The largest impacts were reduced first-quarter earnings and increased third-quarter earnings. This quarterly volatility pattern is expected to continue in the future. Beginning in 1998, annual earnings also will be affected by sales volumes.
Regulatory Accounting Standards SDG&E had been accounting for the economic effects of regulation on all of its utility operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation." Under SFAS No. 71, a regulated entity records a regulatory asset if it is probable that, through the ratemaking process, the utility will recover that asset from customers. Regulatory liabilities represent future reductions in revenues for amounts due to customers.
The SEC indicated a concern that the California IOUs may not meet the criteria of SFAS No. 71 with respect to their electric-generation net regulatory assets. SDG&E has ceased the application of SFAS No. 71 to its generation business, in accordance with the conclusion by the Emerging Issues Task Force of the Financial Accounting Standards Board that the application of SFAS No. 71 should be discontinued when deregulatory legislation is issued that determines that a portion of an entity's business will no longer be regulated. SDG&E's discontinuance of SFAS No. 71 applied to its generation business will not result in a write-off of its net regulatory assets, since the CPUC has approved the recovery of these assets by the distribution portion of its business, subject to the rate freeze.
Consumer Education In August 1997, the CPUC authorized $89 million in rate recovery to fund California's Customer Education Program (CEP). SDG&E's share of this amount is approximately $9 million. The CEP's objective is to provide information to California electric customers to help them compare and choose among electric products and services in a competitive environment. The CEP began in September 1997 and is expected to end by May 31, 1998.
Public-Purpose Programs The CPUC has established a new administrative structure and initial funding levels to manage DSM, renewable-energy, low-income assistance and R&D programs beginning in January 1998. The CPUC has formed independent boards to oversee a competitive bidding process to administer DSM and low-income programs. On an interim basis, the CPUC has required that the California IOUs transfer their administration of DSM and low-income programs to these boards by October 1998, and January 1999, respectively. Until the transition to a fully competitive energy-service market is complete, customers will be required to provide the funding. For 1998, SDG&E will be funded $32 million and $12 million for DSM and renewables programs, respectively. Low-income assistance funding will remain at 1996 authorized levels. The California Energy Commission will be allocated most of the $63 million authorized to administer the R&D programs, of which SDG&E will be funded $4 million. SDG&E's earnings potential from DSM programs will be reduced when the transition to the competitive market is complete.
Federal Restructuring Activities In October 1997, the FERC approved key elements of the California IOUs' restructuring proposal effective January 1, 1998. This includes the transfer by the IOUs of the operational control of their transmission facilities to the ISO, which is under FERC jurisdiction. The FERC also approved, on an interim basis, the establishment of the California PX to operate as an independent wholesale power pool. The California IOUs will pay to the PX a restructuring charge (in four annual installments) and an administrative-usage charge for each megawatt-hour of volume transacted. SDG&E's share of the restructuring charge is approximately $10 million, which is eligible for transition-cost recovery. The IOUs have jointly guaranteed $300 million of commercial loans to the PX and ISO for their development and initial start-up. SDG&E's share of the guarantee is $30 million.
ELECTRIC GENERATION	 In November 1997, SDG&E's Board of Directors approved a plan to auction the company's power plants and other electric-generating assets, enabling SDG&E to continue to concentrate its business on the transmission and distribution of electricity and natural gas as California opens its electric utility industry to competition in 1998. The plan includes the divestiture of SDG&E's fossil power plants - the Encina (Carlsbad, California) and South Bay (Chula Vista, California)
plants - and its combustion turbines, as well as its 20-percent interest in the San Onofre Nuclear Generating Station (SONGS) and its portfolio of long-term purchased-power contracts, including those with qualifying facilities. The power plants, including the interest in SONGS, have a net book value as of December 31, 1997, of $800 million ($200 million for fossil and $600 million for SONGS) and a combined generating capacity of 2,400 megawatts. The proceeds from the auction will be applied directly to SDG&E's transition costs. In December 1997, SDG&E filed with the CPUC for its approval of the auction plan. The sale of the nonnuclear generating assets is expected to be completed by the end of the first quarter of 1999. Although the other California IOUs are required by the CPUC to divest themselves of at least 50 percent of their fossil power plants as a part of industry restructuring, SDG&E is not under the same mandate. Other companies in the free market, not bound by the rules that apply to the state's regulated utilities, are expected to have a greater opportunity to provide competitive generation services with SDG&E's plants. The FERC has ruled that it has jurisdiction over all electricity sales into the California PX, meaning that the buyers of divested California power plants would qualify as wholesale power generators. The FERC's ruling has increased the interest in the nonnuclear plants owned by the other California IOUs, and is expected to have the same impact on SDG&E's fossil plants. As previously discussed, subsidiaries of Enova Energy and Houston Industries have formed a joint venture to build, own and operate a 480- megawatt natural gas-fired power plant in Boulder City, Nevada, 40 miles southeast of Las Vegas. The joint venture, called El Dorado Energy, plans to sell the plant's electricity into the wholesale market to utilities throughout the western United States. The new plant will employ an advanced combined-cycle gas-turbine technology, enabling it to become one of the more efficient and environmentally friendly power plants in the nation. Its proximity to existing natural gas pipelines and electric transmission lines will allow El Dorado to actively compete in the deregulated electric-generation market. Construction on the $280 million project, which will be funded 50 percent each by Enova and Houston Industries, began in the first quarter of 1998, with an expected operational date set for the fourth quarter of 1999.
AFFILIATE TRANSACTION GUIDELINES In December 1997, the CPUC issued a decision on the rules governing transactions between a regulated utility and its affiliates that are not regulated by the CPUC. The decision adopts guidelines that are more favorable to consumers and less restrictive to utilities and their affiliates than the conditions that were recommended in October 1997 by a CPUC administrative law judge's proposed decision and an alternate decision by two CPUC commissioners. Key elements of the decision include: allowing the unregulated affiliates to operate within the utility's service territory without limitation; permitting utilities to share logos with their parent company and unregulated affiliates as long as proper disclaimers to California customers clearly communicate the utility-affiliate relationship; and allowing officers or board of directors of the parent company to also hold positions with the utility or unregulated affiliate, but not both. The rules adopted require separating functions between the utility and the affiliates with the exception of sharing certain corporate support services. These guidelines include transactions between affiliated utilities. However, these transactions have been addressed by the CPUC in the Enova/Pacific Enterprises business combination proceedings and the draft decision arising from that proceeding would exclude transactions between SDG&E and SoCalGas from the guidelines.
PERFORMANCE-BASED RATEMAKING (PBR) Background The CPUC has affirmed its belief that the new competitive environment should be based on policies that encourage efficient operation and improved productivity rather than on reasonableness reviews and disallowances. SDG&E has been participating in a PBR process for base rates, gas procurement, and electric generation and dispatch. SDG&E has applied to extend the Gas Procurement mechanism. The Generation and Dispatch mechanism has been terminated. SDG&E has filed a proposal for a new Distribution PBR mechanism to replace the current experimental Base-Rate PBR when it terminates at the end of 1998.
Base Rates In December 1997, the CPUC approved $6.5 million in performance rewards for SDG&E's 1996 PBR. The CPUC has eliminated the price-performance benchmark indicator, which compares SDG&E's average electric-system rate to a national average, from SDG&E's Base-Rate PBR effective in 1997 due to the electric-rate freeze. For the 1998 PBR, all customer sharing amounts will be credited to the transition-cost balancing account rather than refunded to customers. In December 1997, the CPUC eliminated SDG&E's 1999 General Rate Case filing requirement, and replaced it with a 1999 Cost of Service study in its new Distribution PBR application for electric distribution and gas operations (filed in January 1998 to begin in 1999). The Distribution PBR, which includes six categories of performance indicators, will measure SDG&E's ability to provide efficient, safe and reliable utility transmission (gas only) and distribution services. The application requests a $60 million increase in SDG&E's revenue requirements ($35 million for electric distribution and $25 million for gas). The electric distribution increase does not affect rates and, therefore, reduces the amount available to recover transition costs. Under the new mechanism, all customer-sharing amounts will be reflected as reductions to future rates rather than refunded directly to customers. SDG&E's ability to control its costs within the limits of the revenues authorized by the study will impact future earnings.
1998 Revenues In December 1997, the CPUC approved a $67 million increase in SDG&E's authorized electric distribution revenue requirements and a $7 million increase in gas base rates, effective on January 1, 1998. The electric distribution increase, which reflects 1998 PBR escalations, does not affect rates and, therefore, reduces the amount available to recover transition costs.
Natural Gas In September 1997, SDG&E filed with the CPUC its application for a permanent Gas Procurement PBR mechanism. The filing proposes a mechanism structured around a commodity price cap plus an incremental adjustment, designed to recover transportation costs to the California border. SDG&E is holding settlement discussions with the CPUC's Office of Ratepayer Advocates over the proposed new mechanism.
NATURAL GAS OPERATIONS The ongoing restructuring of the natural gas utility industry has allowed customers to bypass utilities as suppliers and, to a lesser extent, as transporters of natural gas. Currently, nonutility electricity producers and other large customers may use a natural gas utility's facilities to transport gas purchased from other suppliers. Also, smaller customers may form groups to buy natural gas from another supplier. In January 1998, the CPUC opened a rulemaking proceeding designed to open the natural gas industry to all customers, expanding the opportunities of residential and small commercial customers to have access to competing natural gas suppliers. The rulemaking will allow
smaller customers to receive the price and service benefits already realized by larger customers. A potential benefit from future natural gas reform, benefiting both customers and industry participants, would be the opportunity for energy providers to offer integrated retail electric and natural gas service to develop synergies between the two energy markets. In developing a natural gas retail restructuring proposal, the CPUC has provided several guiding principles: replace traditional regulation with competition in those markets where competition or the potential for competition exists, thereby allowing market forces to dictate prices; reform regulation for those utility functions that are not fully competitive; maintain a standard of consumer protection in both competitive and noncompetitive markets; and maintain supply reliability and ensure the safety of consumers' natural gas service. Hearings on the proposed restructuring are scheduled to begin in April 1998, with a final CPUC decision expected to be issued before the end of 1998. Enova's nonutility subsidiaries are involved in several projects to develop natural gas systems in the United States and in Mexico. Discussion on these activities is included herein under "Liquidity and Capital Resources - Investing Activities."
COST OF CAPITAL In October 1997, SDG&E filed with the CPUC its 1998 Market Indexed Capital Adjustment Mechanism (MICAM). MICAM, approved by the CPUC in 1996, adjusts SDG&E's authorized cost of capital based on changes in interest rates. For the current MICAM review, interest-rate movements over the corresponding 12 months did not trigger the mechanism to change, resulting in SDG&E's 1998 cost of capital remaining at 1997 authorized levels of 11.60 percent for the rate of return on equity and 9.35 percent for the rate of return on rate base. Beginning in 1998, MICAM only applies to electric distribution and gas rate base, and excludes the rates of return on nuclear and nonnuclear generating assets (recovered as transition costs), which are authorized at rates of 7.14 percent and 6.75 percent, respectively. During 1998, the CPUC will conduct proceedings to establish separate rates for the electric and gas components. SDG&E's authorized capital structure, which excludes the rate-reduction bonds, remains 49.75 percent common equity, 44.5 percent long-term debt and 5.75 percent preferred stock. Electric transmission rates are regulated by the FERC. SDG&E's 1998 rate of return for transmission is 9.54 percent.
RESOURCE PLANNING Sources of Fuel and Energy SDG&E's primary sources of fuel and purchased power include natural gas from Canada and the Southwest, surplus power from other utilities in the Southwest and the Northwest, and uranium from Canada. Although short-term natural gas supplies are volatile due to weather and other conditions, these sources should provide SDG&E with an adequate supply of competitively priced natural gas. SDG&E has been involved in litigation concerning its long-term contracts for natural gas with four Canadian suppliers. SDG&E has settled with one supplier, with gas being delivered under the terms of the settlement agreement. The remaining suppliers have ceased deliveries pending legal resolution. A U.S. Court of Appeals has upheld a U.S. District Court's decision to invalidate the contracts with two of the suppliers, although the value of the gas delivered has not yet been determined by the court. SDG&E has long-term pipeline capacity commitments related to these contracts for natural gas supplies. If the supply of Canadian natural gas to SDG&E is not resumed, SDG&E intends to use the capacity in other ways, including the release of a portion of this capacity to third parties. SDG&E cannot predict the final outcome of the litigation, but does not expect that an unfavorable outcome would
have a material effect on its financial condition, results of operations or liquidity. Additional information on Canadian gas litigation is discussed in Note 9 of the notes to consolidated financial statements.
San Onofre Nuclear Generating Station In January 1996, the CPUC approved the accelerated recovery of the existing capital costs of Units 2 and 3. The decision allowed SDG&E to recover its remaining investment in the units at a lower rate of return (7.14 percent) over an eight-year period beginning in 1996, rather than over the life of the units' license, which extends to 2013. The accelerated recovery began in April 1996. At December 31, 1997, approximately $600 million was not yet recovered. California electric-industry-restructuring legislation requires that all generation-related stranded assets, which includes the uneconomic sunk costs of Units 2 and 3, be recovered by 2001. The 1996 decision also includes a performance incentive plan that encourages continued, efficient operation of the plant. Under this plan, customers will pay about $0.04 per kilowatt-hour through December 31, 2003. This pricing structure replaces the traditional method of recovering the units' operating expenses and capital improvements. This is intended to make the units more competitive with other sources. The California Coastal Commission (CCC) approved the SONGS owners' preliminary plan to provide 150 acres of wetlands restoration, 150 acres of kelp reef and other mitigation that was ordered by the CCC in April 1997. SDG&E's share of the cost is estimated to be $23 million. Additional information is included under "Water Quality" below. 	While conducting routine inspections of Unit 3 during its scheduled refueling in the second quarter of 1997, it was noted that, in several areas, the thickness of the heat transfer tubes' structural supports was significantly reduced, apparently due to erosion. In June 1997, the Nuclear Regulatory Commission approved the removal of the affected tubes from service as a corrective action and the unit's return to service. Unit 2, which also had this inspection during its scheduled refueling in the first quarter of 1997, showed no signs of this type of erosion. As a precautionary measure, Unit 2 was shut down in January 1998 for a 30-day mid-cycle outage for an inspection of its steam generators. The SONGS owners have scheduled a 30-day outage for Unit 3 in March 1998, for this inspection. The discovery of such problems in the future could increase the possibility that the units would be removed from service prior to 2013.
ENVIRONMENTAL MATTERS SDG&E's operations are conducted in accordance with federal, state and local environmental laws and regulations governing hazardous wastes, air and water quality, land use and solid-waste disposal. SDG&E incurs significant costs to operate its facilities in compliance with these laws and regulations, and to clean up the environment as a result of prior operations of SDG&E or of others. The costs of compliance with environmental laws and regulations are normally recovered in customer rates. However, restructuring of the California electric-utility industry (see "Electric Industry Restructuring" above) will change the way utility rates are set and costs are recovered. SDG&E has proposed a change in the hazardous waste memorandum account to exclude cleanup costs related to electric- generation activities, as described below. Capital costs related to environmental regulatory compliance for electric generation are intended to be included in transition costs for recovery through 2001. However, depending on the final outcome of industry restructuring and the impact of competition, the costs of compliance with future environmental regulations may not be fully recoverable. Capital expenditures to comply with environmental laws and regulations were $4 million in 1997, $6 million in 1996 and $4 million
in 1995, and are expected to be $38 million in the aggregate over the next five years. These expenditures primarily include the estimated cost of retrofitting SDG&E's power plants to reduce air emissions. However, in November 1997 SDG&E announced a plan to auction its power plants and other electric-generating resources. Additional information on SDG&E's plan to divest its electric-generating assets is discussed in Note 10 of the notes to consolidated financial statements.
Hazardous Wastes In 1994, the CPUC approved the Hazardous Waste Collaborative, which allows utilities to recover cleanup costs of hazardous waste contamination at sites where the utility may have responsibility or liability under the law to conduct or participate in any required cleanup. In general, utilities are allowed to recover 90 percent of their cleanup costs and any related costs of litigation with responsible parties. SDG&E has asked the CPUC that beginning on January 1, 1998, the hazardous waste memorandum account be modified to exclude cleanup costs related to electric-generation activities. Electric- generation-related cleanup costs are intended to be eligible for transition cost recovery. A CPUC decision is still pending. SDG&E lawfully disposed of hazardous wastes at facilities owned and operated by other entities. Operations at these facilities may result in actual or threatened risks to the environment or public health. Where the owner or operator of such a facility fails to complete any corrective action required by regulatory agencies to abate such risks, applicable environmental laws may impose an obligation to undertake corrective actions on SDG&E and others who disposed of hazardous wastes at the facility. During the early 1900s, SDG&E and its predecessors manufactured gas from coal and oil at its Station A facility and at two small facilities in Escondido and Oceanside. Certain amounts of residual by-products from the gas manufacturing process and subsurface hydrocarbon contamination were discovered on portions of the Station A site during an environmental assessment which was completed in 1996. A risk assessment has been completed for Station A and demolition was performed during 1997 at a cost of $1 million. Cleanup will commence in 1998, to be completed in 1999, and is estimated to cost $5 million for subsurface remediation. SDG&E also may be required to assess certain off-site contamination which, in part, may have originated from the gas manufacturing process or other operations at Station A. Not included in this estimate are potential costs related to a previously removed shallow underground tank-like structure found under a public street immediately west of Station A. Any potential costs related to this tank would be immaterial. SDG&E is completing negotiations for an appropriate site-remediation work plan for Station A with the County of San Diego Department of Environmental Health. The Escondido facility was remediated during 1990 through 1993 at a cost of $3 million and a site-closure letter from the Department of Environmental Health has been received. However, contaminants similar to those on the Escondido site have been observed on adjacent property. In 1997, SDG&E assessed the nature and extent of these off-site contaminants at a cost of $75,000. Hazardous contaminants were found on property to the east of the site and are believed to have originated from SDG&E operations. Remediation of these contaminants was initiated in 1997 and completed in 1998 at a total cost of $250,000. A site- closure letter has been requested from the Department of Environmental Health. Nonhazardous contaminants were determined to be present on property to the north, but may not require further action subject to future land-use decisions. Finally, potential contaminants resulting from the gas manufacturing process by-products were assessed at the Oceanside facility, as well as on adjacent property. The cost to remediate the hazardous contaminants discovered in the assessment at the
property adjacent to the Oceanside facility and at the facility itself is estimated to be $150,000. Asbestos was used in the construction of SDG&E's Station B power plant, which closed in 1993. Activities to dismantle and decommission the facility require the removal of the asbestos in a manner complying with all applicable environmental, health and safety laws. This work also includes the removal or cleanup of paints containing heavy metals and small amounts of PCBs, fuel oil and other substances. These activities commenced in 1997 at a cost of $3 million. This work effort is expected to be completed in 1998 at an estimated additional cost of $3 million.
Electric and Magnetic Fields (EMFs) In property-damage litigation in 1996, the California Supreme Court agreed with SDG&E and unanimously affirmed the 1995 California Court of Appeal decision that the CPUC has exclusive jurisdiction over EMF health and safety issues. The California Supreme Court also stated that scientific evidence is insufficient to conclude that EMFs pose a health hazard. In addition, in a December 1997 case involving Pacific Gas & Electric, the California Court of Appeal held that the CPUC has exclusive jurisdiction over EMF personal injury, as well as EMF property-damage cases. Plaintiffs have sought review of this case at the California Supreme Court, which request is still pending. Although scientists continue to research the possibility that exposure to EMFs causes adverse health effects, to date, science has demonstrated no cause-and-effect relationship between adverse health effects and exposure to the type of EMFs emitted by utilities, power lines and other electrical facilities. Some laboratory studies suggest that such exposure creates biological effects, but those effects have not been shown to be harmful. The studies that have most concerned the public are certain epidemiological studies, some of which have reported a weak correlation between childhood leukemia and the proximity of homes to certain power lines and equipment. Other epidemiological studies found no correlation between estimated exposure and any disease. Scientists cannot explain why some studies using estimates of past exposure report correlations between estimated EMF levels and disease, while others do not. To respond to public concerns, the CPUC has directed California utilities to adopt a low-cost EMF-reduction policy that requires reasonable design changes to achieve noticeable reduction of EMF levels that are anticipated from new projects. However, consistent with the major scientific reviews of the available research literature, the CPUC has indicated that no health risk has been identified.
Air Quality The San Diego Air Pollution Control District (APCD) regulates air quality in San Diego County in conformance with the California and Federal Clean Air Acts. California's standards are more restrictive than federal standards. During 1996 and 1997, SDG&E installed equipment on South Bay Unit 1 in order to comply with the nitrogen oxide emission limits that the APCD imposed on electric-generating boilers through its Rule 69. Under this rule, SDG&E must maintain the total nitrogen oxide emissions from its entire system below a prescribed emissions cap, which decreases periodically through 2005. The estimated capital costs for compliance with the rule through 2005 are $60 million. The California Air Resources Board has expressed concern that Rule 69 does not meet the requirements of the California Clean Air Act and may advocate or propose more restrictive emissions limitations which will likely cause SDG&E's Rule 69 compliance costs to increase. Under a South Coast Air Quality Management District program called RECLAIM, SDG&E is required to reduce its nitrogen oxide emission levels
of the natural gas compressor engines at its Moreno gas-compression facility by 10 percent a year through 2003. This will be accomplished through the installation of new emission-monitoring equipment, operational changes to take advantage of low-emission engines and engine retrofits. The cost of complying with RECLAIM may be as much as $3 million. 	 Water Quality Wastewater discharge permits issued by the Regional Water Quality Control Board (RWQCB) for SDG&E's Encina and South Bay power plants are required to enable SDG&E to discharge its cooling water and certain other wastewaters into the Pacific Ocean and into San Diego Bay. Wastewater discharge permits are prerequisite to the continued cooling-water and other wastewater discharges and, therefore, the continued operation of the power plants as they are currently configured. Increasingly stringent cooling-water and wastewater discharge limitations may be imposed in the future and SDG&E may be required to build additional facilities or modify existing facilities to comply with these requirements. Such facilities could include wastewater treatment facilities, cooling towers or offshore-discharge pipelines. Any required construction could involve substantial expenditures, and certain plants or units may be unavailable for electric generation during construction. In 1981, SDG&E submitted a demonstration study in support of its request for two exceptions to certain thermal discharge requirements imposed by the California Thermal Plan for Encina power plant Unit 5. In November 1994, the RWQCB issued a new discharge permit, subject to the results of certain additional thermal discharge and cooling water related studies, to be used in considering SDG&E's earlier thermal discharge exception requests. The results of these additional studies were submitted to the RWQCB and the United States Environmental Protection Agency in 1997. If SDG&E's exception requests are denied, SDG&E could be required to construct off-shore discharge facilities at a cost of $75 million to $100 million or to perform mitigation, the costs of which may be significant. In November 1996, the RWQCB issued a new discharge permit to SDG&E for the South Bay power plant. SDG&E filed an appeal to the State Water Resources Control Board (SWRCB) of various provisions which SDG&E considers unduly stringent. The SWRCB has not yet formally acted on the appeal. However, the SWRCB sponsored workshops with the RWQCB and the Environmental Health Coalition in November and December 1997, as a result of which several important issues may be resolved in 1998. As with the Encina power plant, increasingly stringent cooling-water and wastewater discharge limitations may require SDG&E to build additional facilities to comply with these requirements. To comply with its current permit, in 1997 SDG&E diverted its in-plant wastewater discharges from San Diego Bay to the sanitary sewer at a cost of $2 million. During 1997, in conjunction with its permit requirements to treat wastewater at its Encina and South Bay power plants, SDG&E evaluated whether any remediation activities may be required at the power plants based on currently available records and other information. In addition, SDG&E evaluated whether remediation is required at its Silvergate plant, which was shut down in 1984. As a result of these evaluations, only minor and localized remediation efforts were required. However, these evaluations did not include an extensive sampling and analysis of the property at such sites. Extensive sampling and analysis may identify additional contamination or other environmental conditions requiring remediation. As previously discussed, in December 1997, SDG&E filed an application with the CPUC to divest its electric-generating assets, including its Encina and South Bay power plants, gas combustion turbines and its interest in the San Onofre Nuclear Generating Station. As a part
of the sale of any such facilities, SDG&E will complete an environmental baseline analysis of such sites, which may identify significant contamination or other environmental conditions requiring abatement or remediation. The California Coastal Commission (CCC) required a study of the offshore impact on the marine environment from the cooling-water discharge by SONGS Units 2 and 3 as a condition of granting a construction permit. The study concluded that some environmental damage is caused by the discharge. To mitigate the damage, the CCC ordered Southern California Edison, SDG&E and the cities of Anaheim and Riverside to improve the plant's fish-protection system, build a 300- acre artificial reef to help restore kelp beds and restore 150 acres of coastal wetlands. SDG&E and Edison asked the CCC to reconsider and modify this mitigation plan to reduce the size of the artificial reef and shorten the monitoring period based on new studies that show that the environmental damage is much less than anticipated. During 1997 the CCC ordered that the plant owners proceed with a mitigation program that includes the enhanced fish-protection system, a 150-acre artificial reef and restoration of 150 acres of coastal wetlands. In addition, plant owners must deposit $3.6 million with the state for the enhancement of marine fish hatchery programs and pay for state monitoring and oversight of the mitigation projects. SDG&E's share of the cost is estimated to be $23 million. The pricing structure contained in the CPUC's decision regarding accelerated recovery of SONGS Units 2 and 3 (see "San Onofre Nuclear Generating Station" above) likely will accommodate most of these added mitigation costs.
NEW ACCOUNTING STANDARDS In June 1997, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting Comprehensive Income." This statement, which is effective for 1998 financial statements, requires reporting and display of comprehensive income and its components (revenues, expenses, gains and losses) in a full set of general-purpose financial statements. The term "comprehensive income" describes all changes in equity of a business enterprise during a period from transactions and other events including, as applicable, foreign-currency items, minimum pension liability adjustments and unrealized gains and losses on certain investments in debt and equity securities. Upon adoption, financial statements for earlier periods provided for comparative purposes must be restated. The impact on Enova and SDG&E of the adoption of this new accounting standard is considered immaterial to the companies' financial statements. Also in June 1997, the FASB issued SFAS No. 131, "Disclosures about Segments of an Enterprise and Related Information." This statement, which is effective for 1998 financial statements, requires that public companies report certain information about operating segments in complete sets of financial statements of the enterprise and in condensed financial statements of interim periods. It also requires certain information about the company's products and services, geographic areas in which they operate, and their major customers. Under SFAS No. 131, operating segments are to be determined consistent with the way that management organizes and evaluates financial information internally for making operating decisions and assessing performance. Upon adoption, statements for earlier periods provided for comparative purposes must reflect this information. The impact of the adoption of this new accounting standard is the potential redefinition of the company's segments. The company estimates that the primary segments upon adoption of SFAS No. 131 will be electric operations, gas operations, energy services and other.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS This Annual Report to Shareholders includes forward-looking statements within the definition of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. When used in this "Management's Discussion and Analysis of Financial Condition and Results of Operations," the words "estimates," "expects," "anticipates," "plans" and "intends," variations of such words, and similar expressions are intended to identify forward-looking statements that involve risks and uncertainties. Although Enova and SDG&E believe that their expectations are based on reasonable assumptions, they can give no assurance that those expectations will be realized. Important factors that could cause actual results to differ materially from those in the forward-looking statements herein include political developments affecting state and federal regulatory agencies, the pace and substance of electric-industry deregulation in California and in the United States, the ability to effect a coordinated and orderly implementation of both state legislation and the CPUC's restructuring regulations, the consummation and timing of the proposed business combination of Enova and Pacific Enterprises, the timing and level of proceeds of sales of SDG&E's electric-generating assets, the level of sales of electricity, the rate of growth of nonutility subsidiary revenues, international political developments, environmental regulations, and the timing and extent of changes in interest rates and prices for natural gas and electricity.
Item 8.
Item 8. Financial Statements and Supplementary Data - Enova Corporation
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of Enova Corporation:
We have audited the accompanying consolidated balance sheets and the statements of consolidated capital stock and of consolidated long- term debt of Enova Corporation and subsidiaries as of December 31, 1997 and 1996, and the related statements of consolidated income, consolidated changes in capital stock and retained earnings, consolidated cash flows, and consolidated financial information by segments of business for each of the three years in the period ended December 31, 1997. These consolidated financial statements are the responsibility of the Company'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, such consolidated financial statements present fairly, in all material respects, the financial position of Enova Corporation and 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.
/S/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP San Diego, California February 23, 1998
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ENOVA CORPORATION
NOTE 1: BUSINESS COMBINATION In October 1996 Enova Corporation and Pacific Enterprises (PE), parent company of Southern California Gas Company (SoCalGas), announced an agreement to combine the two companies. As a result of the combination, (i) each outstanding share of common stock of Enova will be converted into one share of common stock of the new company, (ii) each outstanding share of common stock of PE will be converted into 1.5038 shares of common stock of the new company and (iii) the preferred stock and preference stock of SDG&E, PE and SoCalGas will remain outstanding. 	The combination was unanimously approved by the boards of directors of both companies and subsequently was approved by the shareholders of both companies. The combination will be a tax-free transaction and is expected to be accounted for as a pooling of interests. Enova and PE have selected Sempra Energy as the name of the new combined company, with the corporate headquarters to be located in San Diego, California. Headquarters for SDG&E and SoCalGas, whose names will be retained, will remain in San Diego and Los Angeles, California, respectively. Consummation of the combination is conditional upon the approvals of the California Public Utilities Commission and various other regulatory bodies, with completion expected in the summer of 1998. On February 23, 1998, the CPUC's administrative law judge handling the proceeding issued a draft decision that proposed approval of the combination. Among other things, the draft decision proposed 50/50 sharing of the net cost savings resulting from the combination between shareholders and customers, but only for five years rather than the 10 years sought. The draft decision would reduce the net shareholder savings from $1.1 billion to $340 million. The CPUC decision is scheduled for the end of March 1998. Additional information concerning Enova/PE joint activities is discussed in Note 3.
NOTE 2: SIGNIFICANT ACCOUNTING POLICIES Nature of Operations On January 1, 1996, Enova Corporation (referred to herein as Enova, which includes the parent and its wholly owned subsidiaries) became the parent of SDG&E and its unregulated subsidiaries (referred to herein as nonutility subsidiaries). SDG&E's outstanding common stock was converted on a share-for-share basis into Enova common stock. SDG&E's debt securities, preferred and preference stock were unaffected and remain with SDG&E. 	The consolidated financial statements include Enova and its wholly owned subsidiaries. The subsidiaries include SDG&E, Califia, Enova Financial, Enova Energy, Enova Technologies, Enova International and Pacific Diversified Capital. In 1997, nonutility subsidiaries contributed 8 percent to operating income (8 percent in 1996 and 9 percent in 1995).
Utility Plant and Depreciation Utility plant represents the buildings, equipment and other facilities used by SDG&E to provide electric and gas service. The cost of utility plant includes labor, materials, contract services and related items, and an allowance for funds used during construction. The cost of retired depreciable utility plant, plus removal costs minus salvage value is charged to accumulated depreciation. Information regarding industry restructuring and its effect on utility plant is included in Note 10. Utility plant in service by major functional categories at December 31, 1997, are: electric generation $1.8 billion, electric distribution $2.3 billion, electric transmission $0.7 billion, other electric $0.3 billion and gas operations $0.8 billion. The corresponding amounts at December 31, 1996, were essentially the same as 1997. Accumulated depreciation and decommissioning of electric and gas utility plant in service at December 31, 1997, are $2.6 billion and $0.4 billion, respectively, and at December 31, 1996, were $2.2 billion and $0.4 billion, respectively.
Depreciation expense is based on the straight-line method over the useful lives of the assets or a shorter period prescribed by the California Public Utilities Commission (CPUC) (for SONGS, see below). The provisions for depreciation as a percentage of average depreciable utility plant (by major functional categories) in 1997 and (in 1996, 1995, respectively) are: electric generation 8.83 (7.57, 4.04), electric distribution 4.39 (4.38, 4.36), electric transmission 3.28 (3.25, 3.21), other electric 6.02 (5.95, 5.89) and gas operations 4.03 (4.07, 4.06). The increases for electric generation in 1997 and 1996 reflect the accelerated recovery of San Onofre Nuclear Generating Station (SONGS) Units 2 and 3 approved by the CPUC in April 1996.
Inventories Included in inventories at December 31, 1997, are SDG&E's $43 million of materials and supplies ($40 million in 1996), and $22 million of fuel oil and natural gas ($23 million in 1996). Materials and supplies are valued at average cost; fuel oil and natural gas are valued by the last-in first-out (LIFO) method.
Other Current Assets Included in other current assets at December 31, 1997, is $44 million for Enova's current and deferred income taxes ($47 million in 1996). Included therein is SDG&E's portion of $26 million ($33 million in 1996).
Short-term Borrowings There were no short-term borrowings at December 31, 1997, and 1996. At December 31, 1997, SDG&E had $50 million of bank lines available to support commercial paper. Commitment fees are paid on the unused portion of the lines and there are no requirements for compensating balances.
Other Current Liabilities Included in other current liabilities at December 31, 1997, is Califia's $21 million current portion of deferred lease revenue ($33 million in 1996) and $35 million for SDG&E's accrued vacation and sick leave ($33 million in 1996). In 1996 the $21 million noncurrent portion of Califia's deferred lease revenue is included in "Deferred Credits and Other Liabilities." The deferred revenue is amortized over the lease terms that end in 1998.
Allowance for Funds Used During Construction (AFUDC) The allowance represents the cost of funds used to finance the construction of utility plant and is added to the cost of utility plant. AFUDC also increases income, as an offset to interest charges shown in the Statements of Consolidated Income, although it is not a current source of cash. The average rate used to compute AFUDC was 9.35 percent in 1997, 9.36 percent in 1996 and 9.74 percent in 1995.
Effects of Regulation SDG&E's accounting policies conform with generally accepted accounting principles for regulated enterprises and reflect the policies of the CPUC and the Federal Energy Regulatory Commission. SDG&E has been preparing its financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation," under which a regulated utility may record a regulatory asset if it is probable that, through the ratemaking process, the utility will recover that asset from customers. Regulatory liabilities represent future reductions in revenues for amounts due to customers. To the extent that a portion of SDG&E's operations is no longer subject to SFAS No. 71, or recovery is no longer probable as a result of changes in regulation or SDG&E's competitive position, the related regulatory assets and liabilities would be written off. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets to Be Disposed Of," affects utility plant and regulatory assets such that a loss must be recognized whenever a regulator excludes all or part of an asset's cost from rate base. As discussed in Note 10, California enacted a law restructuring the electric utility industry. The law adopts the December 1995 CPUC policy decision, and allows California utilities the opportunity to recover existing utility plant and regulatory assets over a transition period that ends in 2001. SDG&E has ceased the application of SFAS No. 71 with respect to its electric-generation business. SDG&E continues to evaluate the applicability of SFAS No. 121 as industry restructuring progresses. Additional information
concerning regulatory assets and liabilities is described below in "Revenues and Regulatory Balancing Accounts" and in Note 10.
Revenues and Regulatory Balancing Accounts Revenues from utility customers have consisted of deliveries to customers and the changes in regulatory balancing accounts. Earnings fluctuations from changes in the costs of fuel oil, purchased energy and natural gas, and consumption levels for electricity and the majority of natural gas previously were eliminated by balancing accounts authorized by the CPUC. This is still the case for natural gas sales. However, as a result of California's electric-restructuring law, beginning in 1997 overcollections recorded in the Energy Cost Adjustment Clause (ECAC) and Electric Revenue Adjustment Mechanism (ERAM) balancing accounts were transferred to the interim transition cost-balancing account, which is being applied to transition cost recovery (see Note 10). At December 31, 1997, overcollections of $130 million were included in this account. Of this amount, $98 million of overcollections were recorded at December 31, 1996. The elimination of ECAC and ERAM resulted in quarter-to-quarter earnings volatility in 1997. This earnings volatility will continue in future years. Additional information on industry restructuring is included in Note 10.
Deferred Charges and Other Assets Deferred charges include SDG&E's unrecovered premium on early retirement of debt and other regulatory- related expenditures that SDG&E expects to recover in future rates, excluding generation operations (discussed above). These items are amortized as recovered in rates. The net regulatory assets associated with SDG&E's generation operations at December 31, 1997, were credited to the interim transition cost balancing account.
Deferred Credits and Other Liabilities Other liabilities at December 31, 1997, include $117 million of accumulated decommissioning costs associated with SONGS Unit 1 ($96 million in 1996), which was permanently shut down in 1992. Additional information on SONGS Unit 1 decommissioning costs is included in Note 5. 	
Discontinued Operations Enova's financial statements for periods prior to 1996 reflect the June 1995 sale of Wahlco Environmental Systems, Inc. as discontinued operations, in accordance with Accounting Principles Board Opinion No. 30, "Reporting the Effects of a Disposal of a Segment of Business." Discontinued operations are summarized in the table below:
In millions of dollars 1995 - --------------------------------------------------------------------- Revenues $ 24 Loss from operations before income taxes -- Loss on disposal before income taxes (12) Income tax benefits 12
The loss on disposal of Wahlco reflects the sale of Wahlco and Wahlco's 1995 net operating losses prior to the sale.
Use of Estimates in the Preparation of Financial Statements The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Statements of Consolidated Cash Flows Temporary investments are highly liquid investments with original maturities of three months or less, or investments that are readily convertible to cash.
Basis of Presentation Certain prior-year amounts have been reclassified to conform to the current year's format.
NOTE 3: SIGNIFICANT ACQUISITIONS AND JOINT VENTURES Sempra Energy Trading On December 31, 1997, Enova and Pacific Enterprises completed their acquisition (50% interest each) of Sempra Energy Trading (formerly AIG Trading Corporation), a leading natural gas and power marketing firm headquartered in Greenwich, Connecticut, for a total cost of $225 million. Sempra Energy Trading's primary business focus is wholesale trading and marketing of natural gas, power and oil to customers primarily in North America. Sempra Energy Trading had net assets of $30 million at December 31, 1997. An allocation of the purchase price has not yet been completed. The difference between the cost and underlying equity in the net assets will be amortized over a period of not more than 15 years. As of December 31, 1997, Sempra Energy Trading's trading assets and trading liabilities approximate the following:
In millions of dollars - --------------------------------------------------------------------- Trading Assets Unrealized gains on swaps and forwards $ 497 Due from commodity clearing organization and clearing brokers 41 OTC commodity options purchased 33 Due from trading counterparties 16 - --------------------------------------------------------------------- Total $ 587 =====================================================================
Trading Liabilities Unrealized losses on swaps and forwards $ 487 Due to trading counterparties 41 OTC commodity options written 29 - --------------------------------------------------------------------- Total $ 557 =====================================================================
	The notional amounts of Sempra Energy Trading's financial instruments are provided below and include a maturity profile as of December 31, 1997, based upon the expected timing of the future cash flows. The notional amounts do not necessarily represent the amounts exchanged by parties to the financial instruments and do not measure Sempra Energy Trading's exposure to credit or market risks. The notional or contractual amounts are used to summarize the volume of financial instruments, but do not reflect the extent to which positions may offset one another. Accordingly, Sempra Energy Trading is exposed to much smaller amounts potentially subject to risk.
Enova and Pacific Enterprises have jointly and severally guaranteed certain trading obligations of Sempra Energy Trading with credit worthy counterparties in connection with authorized transactions and in connection with funding. The total obligations guaranteed by the companies as of December 31, 1997, are $190 million.
Sempra Energy Solutions In January 1998 Sempra Energy Solutions completed the acquisition of CES/Way International, a leading national energy-service
provider. In September 1997 Sempra Energy Solutions formed a joint venture with Bangor Hydro to build, own and operate a $40 million natural gas distribution system in Bangor, Maine. In December 1997, Sempra Energy Solutions signed a partnership agreement with Frontier Utilities to build and operate a $55 million natural gas distribution system in North Carolina. 	 Enova International Gas Distribution Projects Enova International, Pacific Enterprises International and Proxima S.A. de C.V., partners in the Mexican companies Distribuidora de Gas Natural de Mexicali and Distribuidora de Gas Natural de Chihuahua, are the licensees to build and operate natural gas distribution systems in Mexicali and Chihuahua. DGN - Mexicali will invest up to $25 million during the first five years of the 30-year license period. DGN - Chihuahua plans to invest $50 million in the gas distribution project in Chihuahua over the next five years. 	 El Dorado Power Project In December 1997 Enova Power Corporation, a subsidiary of Enova Energy, and Houston Industries Power Generation (HIPG) formed a joint venture, El Dorado Energy, to build, own and operate a 480-megawatt natural gas-fired plant in Boulder City, Nevada. Total cost of construction is expected to be $280 million, with each company providing 50 percent of the funding. Enova Power and HIPG each will be responsible for 50 percent of the plant's fuel procurement and output marketing. Construction on the plant is expected to begin in the first quarter of 1998 and be completed in the fourth quarter of 1999.
NOTE 4: LONG-TERM DEBT Amounts and due dates of long-term debt are shown on the Statements of Consolidated Long-Term Debt. Excluding capital leases, which are described in Note 9, maturities of long-term debt for SDG&E are $66 million due in 1998, $65 million due in 1999, 2000 and 2001, and $145 million due in 2002. Total maturities of long-term debt for nonutility subsidiaries are $49 million for 1998, $53 million for 1999, $44 million for 2000, $35 million for 2001 and $34 million for 2002. SDG&E has CPUC authorization to issue an additional $185 million in long-term debt.
First Mortgage Bonds First mortgage bonds are secured by a lien on substantially all of SDG&E's utility plant. Additional first mortgage bonds may be issued upon compliance with the provisions of the bond indenture, which provides for, among other things, the issuance of an additional $1.3 billion of first mortgage bonds at December 31, 1997. Certain first mortgage bonds may be called at SDG&E's option. First mortgage bonds totaling $249 million have variable-interest- rate provisions. During 1997, SDG&E retired $127 million of first mortgage bonds, of which $102 million were retired prior to scheduled maturity.
Unsecured Bonds During 1997, SDG&E issued $25 million of unsecured bonds. Unsecured bonds totaling $124 million have variable-interest-rate provisions.
Rate-Reduction Bonds In December 1997, $658 million of rate-reduction bonds were issued on behalf of SDG&E at an average interest rate of 6.26 percent. These bonds were issued to facilitate the 10-percent rate reduction mandated by California's electric-restructuring law. These bonds are being repaid over 10 years by SDG&E's residential and small- commercial customers via a charge on their electricity bills. These bonds are secured by the revenue streams collected from customers and are not secured by, or payable from, utility assets. Additional information on rate-reduction bonds and electric industry restructuring is discussed in Note 10.
Other At December 31, 1997, SDG&E had $340 million of bank lines, providing a committed source of long-term borrowings, with no debt outstanding. Bank lines, unless renewed by SDG&E, expire in 1998 ($60 million) and in 2000 ($280 million). Commitment fees are paid on the unused portion of the lines and there are no requirements for compensating balances.
Nonutility loans (Enova Financial and Califia) of $318 million and $231 million at December 31, 1997, and 1996, respectively, are secured by real estate and equipment. SDG&E's interest payments, including those applicable to short-term borrowings, amounted to $89 million in 1997, $93 million in 1996 and $100 million in 1995. Nonutility interest payments amounted to $12 million in 1997, $12 million in 1996 and $14 million in 1995. 	 SDG&E periodically enters into interest-rate swap and cap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowings. At December 31, 1997, SDG&E had such an agreement, maturing in 2002, with underlying debt of $45 million. See additional information in Note 8. 	 Although holders of variable-rate bonds may elect to redeem them prior to scheduled maturity, for purposes of determining the maturities listed above, it is assumed the bonds will be held to maturity.
NOTE 5: FACILITIES UNDER JOINT OWNERSHIP SONGS and the Southwest Powerlink transmission line are owned jointly with other utilities. SDG&E's interests at December 31, 1997, are:
In millions of dollars - ---------------------------------------------------------------------- Southwest Project SONGS Powerlink - ---------------------------------------------------------------------- Percentage ownership 20 89 Utility plant in service $1,143 $ 217 Accumulated depreciation $ 593 $ 96 Construction work in progress $ 9 $ --
	SDG&E's share of operating expenses is included in the Statements of Consolidated Income. Each participant in the projects must provide its own financing. The amounts specified above for SONGS include nuclear production, transmission and other facilities.
SONGS Decommissioning Objectives, work scope and procedures for the future dismantling and decontamination of the SONGS units must meet the requirements of the Nuclear Regulatory Commission, the Environmental Protection Agency, the California Public Utilities Code and other regulatory bodies. 	 SDG&E's share of decommissioning costs for the SONGS units is estimated to be $401 million in current dollars and is based on studies performed and updated periodically by outside consultants. The most recent study was performed in 1993. A new study is planned for 1998. A new escalation methodology was utilized to estimate the liability in 1997. This methodology was authorized by the CPUC in its 1996 Performance-Based Ratemaking decision for Southern California Edison (principal owner of SONGS), and incorporates an internal rate of return calculation that results in higher escalation amounts. Although electric industry restructuring legislation requires that stranded costs, which include SONGS plant costs, be amortized in rates by 2001, the recovery of decommissioning costs is allowed until the time as the costs are fully recovered. The amount accrued each year is based on the amount allowed by regulators and is currently being collected in rates. This amount is considered sufficient to cover SDG&E's share of future decommissioning costs. The depreciation and decommissioning expense reflected on the Statements of Consolidated Income includes $22 million of decommissioning expense for each of the years 1997, 1996 and 1995. The amounts collected in rates are invested in externally managed trust funds. In accordance with SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities," the securities held by the trust are considered available for sale and are adjusted to market value ($399 million at December 31, 1997, and $328 million at December 31, 1996) and shown on the Consolidated Balance Sheets. The fair values reflect unrealized gains of $89 million and $50 million at December 31, 1997, and 1996, respectively. The corresponding accumulated accrual is included on the Consolidated Balance Sheets in
"Accumulated Depreciation and Decommissioning" for SONGS Units 2 and 3 and in "Deferred Credits and Other Liabilities" for Unit 1. SONGS Unit 1 was permanently shut down in 1992. 	The Financial Accounting Standards Board is reviewing the accounting for liabilities related to closure and removal of long-lived assets, such as nuclear power plants, including the recognition, measurement and classification of such costs. The Board could require, among other things, that SDG&E's future balance sheets include a liability for the estimated decommissioning costs, and a related increase in the cost of utility plant. 	Additional information regarding SONGS is included in Notes 9 and 10.
NOTE 6: EMPLOYEE BENEFIT PLANS Pension Plan SDG&E has a defined-benefit pension plan, which covers substantially all of its employees. Benefits are related to the employees' compensation. Plan assets consist primarily of common stocks and bonds. SDG&E funds the plan based on the projected unit credit actuarial cost method. Net pension cost consisted of the following for the years ended December 31:
In thousands of dollars 1997 1996 1995 - ---------------------------------------------------------------------- Cost related to current service $16,756 $18,547 $14,598 Interest on projected benefit obligation 39,089 37,253 30,760 Return on plan assets (119,554) (72,829) (132,674) Net amortization and deferral 63,500 25,315 93,708 - ---------------------------------------------------------------------- Cost pursuant to general accounting standards (209) 8,286 6,392 Regulatory adjustment -- (15,286) 608 - ---------------------------------------------------------------------- Net cost (benefit) $ (209) $(7,000) $7,000 ======================================================================
	The plan's status was as follows at December 31:
In thousands of dollars 1997 1996 - ---------------------------------------------------------------------- Accumulated benefit obligation Vested $495,278 $435,029 Non-vested 11,637 12,321 - ---------------------------------------------------------------------- Total $506,915 $447,350 ======================================================================
Plan assets at fair value $699,000 $598,610 Projected benefit obligation 589,911 539,391 - ---------------------------------------------------------------------- Plan assets less projected benefit obligation 109,089 59,219 Unrecognized effect of accounting change (761) (950) Unrecognized prior service cost 28,444 31,315 Unrecognized actuarial gains (204,061) (157,082) - ---------------------------------------------------------------------- Net liability $(67,289) $(67,498) ======================================================================
The projected benefit obligation assumes a 7.25 percent actuarial discount rate in 1997 (7.50 percent in 1996) and a 5.0 percent average annual compensation increase. The expected long-term rate of return on plan assets is 8.5 percent. The increase in the total accumulated benefit obligation and projected benefit obligation at December 31, 1997, is due primarily to a decrease in the actuarial discount rate. SDG&E's annual cost for a supplemental retirement plan for a limited number of key employees was approximately $3 million in 1997, 1996 and 1995.
Post-Retirement Health Benefits SDG&E provides certain health and life insurance benefits to retired employees. These benefits are accrued during the employee's years of service, up to the year of benefit eligibility. SDG&E is recovering the cost of these benefits based upon actuarial calculations and funding limitations. The costs for the benefits were $4 million in 1997, $5 million in 1996 and $5 million in 1995. These costs include $2 million of amortization per year for the unamortized transition obligation (arising from the initial implementation of this accounting policy) of approximately $31 million, which is being amortized through 2012.
Savings Plan Essentially all employees are eligible to participate in SDG&E's savings plan. Eligible employees may make a contribution of 1 percent to 15 percent of their base pay to the savings plan for investment in mutual funds or in Enova common stock. SDG&E contributes amounts equal to up to 3 percent of participants' compensation for investment in Enova common stock. SDG&E's annual compensation expense for this plan was $3 million in 1997, $2 million in 1996 and $2 million in 1995.
Stock-Based Compensation Enova has a long-term incentive stock compensation plan that provides for aggregate awards of up to 2,700,000 shares of Enova common stock. The plan terminates in April 2005. In each of the last 10 years, 49,000 shares to 75,000 shares of stock were issued to officers and key employees, subject to forfeiture over four years if certain corporate goals are not met. The long-term incentive stock compensation plan also provides for the granting of stock options. In October 1997, Enova rescinded all options granted in October 1996. There were no stock options outstanding at December 31, 1997. As permitted by SFAS No. 123, "Accounting for Stock-Based Compensation," SDG&E has adopted the disclosure-only requirements of SFAS No. 123 and continues to account for stock-based compensation by applying the provisions of Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." The differences between compensation cost included in net income and the related cost measured by the fair- value-based method defined in SFAS No. 123 are immaterial. SDG&E's compensation expense for this plan was approximately $1 million in 1997, $1 million in 1996 and $2 million in 1995.
NOTE 7: INCOME TAXES Income tax payments totaled $162 million in 1997, $176 million in 1996 and $148 million in 1995. The components of accumulated deferred income taxes at December 31 are as follows:
In thousands of dollars 1997 1996 - ---------------------------------------------------------------------- Deferred tax liabilities Differences in financial and tax bases of utility plant $567,804 $628,617 Loss on reacquired debt 30,535 26,399 Other 91,708 80,033 - ---------------------------------------------------------------------- Total deferred tax liabilities 690,047 735,049 - ---------------------------------------------------------------------- Deferred tax assets Unamortized investment tax credits 62,144 66,729 Equipment leasing activities 8,494 22,333 Regulatory balancing accounts 27,903 37,010 Unbilled revenue 22,365 21,923 Other 89,856 123,158 - --------------------------------------------------------------------- Total deferred tax assets 210,762 271,153 - --------------------------------------------------------------------- Net deferred income tax liability 479,285 463,896 Current portion (net asset) 21,745 33,504 - --------------------------------------------------------------------- Non-current portion (net liability) $501,030 $497,400 =====================================================================
	The components of income tax expense are as follows:
In thousands of dollars 1997 1996 1995 - --------------------------------------------------------------------- Current Federal $93,040 $115,410 $134,212 State 38,413 39,939 42,630 - --------------------------------------------------------------------- Total current taxes 131,453 155,349 176,842 - --------------------------------------------------------------------- Deferred Federal 23,222 434 (23,914) State 1,600 (1,518) (13,464) - --------------------------------------------------------------------- Total deferred taxes 24,822 (1,084) (37,378) - --------------------------------------------------------------------- Deferred investment tax credits - net (6,073) (5,791) (4,859) - --------------------------------------------------------------------- Total income tax expense $150,202 $148,474 $134,605 =====================================================================
Federal and state income taxes are allocated between operating income and other income.
	The reconciliation of the statutory federal income tax rate to the effective income tax rate is as follows:
1997 1996 1995 - --------------------------------------------------------------------- Statutory federal income tax rate 35.0 % 35.0 % 35.0 % Depreciation 8.1 6.3 5.5 State income taxes - net of federal income tax benefit 7.0 6.9 5.5 Tax credits (10.8) (9.5) (7.6) Equipment leasing activities (2.3) (2.8) (2.8) Repair allowance (1.9) (1.2) (3.0) Other - net 2.3 4.4 4.8 - --------------------------------------------------------------------- Effective income tax rate 37.4 % 39.1 % 37.4 % =====================================================================
NOTE 8: FINANCIAL INSTRUMENTS Fair Value The fair values of financial instruments (cash, temporary investments, funds held in trust, notes receivable, investments in limited partnerships, dividends payable, short- and long-term debt, deposits from customers, and preferred stock subject to mandatory redemption) are not materially different from the carrying amounts, except for long-term debt. The carrying amounts and fair value of long- term debt are $2.1 billion and $2.2 billion, respectively, at December 31, 1997, and $1.5 billion and $1.5 billion, respectively, at December 31, 1996. The fair values of SDG&E's first mortgage bonds are estimated based on quoted market prices for them or for similar issues. The fair values of long-term notes payable are based on the present values of the future cash flows, discounted at rates available for similar notes with comparable maturities. The fair values of the rate-reduction bonds issued in December 1997 are estimated to approximate carrying value due to the relatively short period of time between the issuance date and the valuation date, and the relative market stability during those periods.
Off-Balance-Sheet Financial Instruments Enova's policy is to use derivative financial instruments to reduce its exposure to fluctuations in interest rates, foreign-currency exchange rates and natural gas prices. These financial instruments expose Enova to market and credit risks which may at times be concentrated with certain counterparties, although counterparty nonperformance is not anticipated.
Interest-Rate-Swap Agreements SDG&E periodically enters into interest- rate-swap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowing. These swap agreements generally remain off the balance sheet as they involve the exchange of fixed- and variable-rate interest payments without the exchange of the underlying principal amounts. The related gains or losses are reflected in the income statement as part of interest expense. At December 31, 1997, SDG&E had one interest-rate-swap agreement: a floating-to-fixed- rate swap associated with $45 million of variable-rate bonds maturing in 2002. SDG&E expects to hold this derivative financial instrument to its maturity. This swap agreement has effectively fixed the interest rate on the underlying variable-rate debt at 5.4 percent. SDG&E would be exposed to interest-rate fluctuations on the underlying debt should the counterparty to the agreement not perform. Such nonperformance is not anticipated. This agreement, if terminated, would result in an obligation of $2 million at December 31, 1997, and at December 31, 1996.
Foreign-Currency Forward Exchange Contracts SDG&E's pension fund periodically uses foreign-currency forward contracts to reduce its exposure to exchange-rate fluctuations associated with certain investments in foreign equity securities. These contracts generally have maturities ranging from three to six months. At December 31, 1997, there were no foreign-currency forward contracts outstanding.
Energy Derivatives SDG&E uses energy derivatives for both hedging and trading purposes within certain limitations imposed by company policies. These derivative financial instruments include forward contracts, swaps, options and other contracts which have maturities ranging from 30 days to nine months. SDG&E's accounting policy is to adjust the book value of these derivatives to market each month with gains and losses recognized in earnings. These instruments are included in other current assets on the Consolidated Balance Sheet. Certain instruments such as swaps are entered into and closed out within the same month and, therefore, do not have any balance-sheet impact. Gains and losses are included in electric or gas revenue or expense, whichever is appropriate, on the Consolidated Income Statement. 	As of December 31, 1997, the net fair value of open positions was $5.9 million. The net unrealized profit of these open positions was $0.3 million. These positions hedge approximately 6 percent of SDG&E's annual total purchased-gas volumes. The average fair value of derivative financial instruments during 1997 was an obligation of $0.2 million. The net gains arising from these activities during 1997 were $2.5 million. Information on derivative financial instruments of Sempra Energy Trading is provided in Note 3.
Market and Credit Risk SDG&E and Sempra Energy Trading utilize a variety of financial structures, products and terms which require the company to manage, on a portfolio basis, the resulting market risks inherent in these transactions, subject to parameters established by company policies. Market risks are monitored separately from the groups that create or actively manage these risk exposures to ensure compliance with the company's stated risk management policies. Credit risk relates to the risk of loss that would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. SDG&E and Sempra Energy Trading avoid concentration of counterparties and maintain credit policies with regard to counterparties that management believes significantly minimize overall credit risk. A Risk Management Committee, composed of Enova and Pacific Enterprises officers, is responsible for monitoring operating performance and compliance with established risk management policies for Sempra Energy Solutions and its subsidiaries.
NOTE 9: CONTINGENCIES AND COMMITMENTS Purchased-Power Contracts SDG&E buys electric power under several short-term and long-term contracts. Purchases are for up to 7 percent of plant capacity under contracts with other utilities and up to 100 percent of plant capacity under contracts with nonutility suppliers. No one supplier provides more than 3 percent of SDG&E's total system requirements. The contracts expire on various dates between 1998 and 2025.
	At December 31, 1997, the estimated future minimum payments under the contracts were:
In millions of dollars - --------------------------------------------------------------------- 1998 $234 1999 232 2000 200 2001 183 2002 134 Thereafter 2,462 - --------------------------------------------------------------------- Total minimum payments $3,445 =====================================================================
These payments represent capacity charges and minimum energy purchases. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. Total payments, including energy payments, under the contracts were $421 million in 1997, $296 million in 1996
and $329 million in 1995. Payments under purchased-power contracts increased in 1997 due to increased sales volume and lower nuclear generation availability. In November 1997, SDG&E announced a plan to auction its power plants and other electric-generating resources, which include its long-term purchased-power contracts. Additional information on SDG&E's plan to divest its electric-generating assets is discussed in Note 10.
Natural Gas Contracts SDG&E has a contract with Southern California Gas Company (SoCalGas) that provides SDG&E with intrastate transportation capacity on SoCalGas' pipelines. This contract is currently being renegotiated and continues on a month-to-month basis under the original terms until a new agreement is reached. The commitment presumes a contract renewal for one year. SDG&E's long-term contracts with interstate pipelines for transportation capacity expire on various dates between 2007 and 2023. SDG&E's contract with SoCalGas for 8 billion cubic feet of natural gas storage capacity expires in March 1998. A new agreement has been reached for 6 billion cubic feet of natural gas storage capacity from April 1998 through March 1999. SDG&E has long-term natural gas supply contracts (included in the table below) with four Canadian suppliers that expire between 2001 and 2004. SDG&E has been involved in negotiations and litigation with the suppliers concerning the contracts' terms and prices. SDG&E has settled with one supplier, with gas being delivered under the terms of the settlement agreement. The remaining suppliers have ceased deliveries pending legal resolution. A U.S. Court of Appeals has upheld a U.S. District Court's invalidation of the contracts with two of these suppliers, although the value of the gas delivered has not yet been determined by the court. 	At December 31, 1997, the future minimum payments under natural gas contracts were: Transportation Natural In millions of dollars and Storage Gas - ---------------------------------------------------------------------- 1998 $65 $19 1999 15 17 2000 14 19 2001 14 21 2002 14 24 Thereafter 234 25 - ---------------------------------------------------------------------- Total minimum payments $356 $125 ======================================================================
	Total payments under the contracts were $125 million in 1997, $100 million in 1996 and $95 million in 1995.
Leases SDG&E has nuclear fuel, office buildings, a generating facility and other properties that are financed by long-term capital leases. Utility plant includes $198 million at December 31, 1997, and $200 million at December 31, 1996, related to these leases. The associated accumulated amortization is $102 million and $95 million, respectively. SDG&E and nonutility subsidiaries also lease office facilities, computer equipment and vehicles under operating leases. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 2 percent to 7 percent. 	The minimum rental commitments payable in future years under all noncancellable leases are:
Operating Capitalized Leases Leases In millions of dollars Enova SDG&E SDG&E - --------------------------------------------------------------------- 1998 $35 $13 $26 1999 12 12 26 2000 12 12 20 2001 8 8 12 2002 8 8 12 Thereafter 36 36 20 - --------------------------------------------------------------------- Total future rental commitment $111 $89 116 - --------------------------------------------------------------------- Imputed interest (6% to 9%) (21) - --------------------------------------------------------------------- Net commitment $95 =====================================================================
Enova's rental payments totaled $81 million in 1997, $88 million in 1996 and $85 million in 1995. Included in these amounts are SDG&E payments of $43 million, $46 million and $44 million, respectively.
Environmental Issues SDG&E's operations are conducted in accordance with federal, state and local environmental laws and regulations governing hazardous wastes, air and water quality, land use, and solid- waste disposal. SDG&E incurs significant costs to operate its facilities in compliance with these laws and regulations. The costs of compliance with environmental laws and regulations have been recovered in customer rates. Capital expenditures to comply with environmental laws and regulations were $4 million in 1997, $6 million in 1996 and $4 million in 1995, and are expected to be $38 million over the next five years. These expenditures primarily include the estimated cost of retrofitting SDG&E's power plants to reduce air emissions. SDG&E has been associated with various sites which may require remediation under federal, state or local environmental laws. SDG&E is unable to determine the extent of its responsibility for remediation of these sites until assessments are completed. Furthermore, the number of others that also may be responsible, and their ability to share in the cost of the cleanup, is not known. Environmental liabilities that may arise from these assessments are recorded when remedial efforts are probable, and the costs can be estimated. In 1994 the CPUC approved the Hazardous Waste Collaborative Memorandum account allowing utilities to recover their hazardous waste costs, including those related to Superfund sites or similar sites requiring cleanup. The decision allows recovery of 90 percent of cleanup costs and related third-party litigation costs and 70 percent of the related insurance-litigation expenses. As discussed in Note 10, restructuring of the California electric-utility industry will change the way utility rates are set and costs are recovered. Both the CPUC and state legislation have indicated that the California utilities will be allowed an opportunity to recover existing utility plant and regulatory assets over a transition period that ends in 2001. SDG&E has asked the CPUC that beginning on January 1, 1998, the collaborative account be modified, and that electric- generation-related cleanup costs be eligible for transition cost recovery. A CPUC decision is still pending. Depending on the final outcome of industry restructuring and the impact of competition, the
costs of compliance with environmental regulations may not be fully recoverable.
Nuclear Insurance SDG&E and the co-owners of SONGS have purchased primary insurance of $200 million, the maximum amount available, for public-liability claims. An additional $8.7 billion of coverage is provided by secondary financial protection required by the Nuclear Regulatory Commission and provides for loss sharing among utilities owning nuclear reactors if a costly accident occurs. SDG&E could be assessed retrospective premium adjustments of up to $32 million in the event of a nuclear incident involving any of the licensed, commercial reactors in the United States, if the amount of the loss exceeds $200 million. In the event the public-liability limit stated above is insufficient, the Price-Anderson Act provides for Congress to enact further revenue-raising measures to pay claims, which could include an additional assessment on all licensed reactor operators. Insurance coverage is provided for up to $2.8 billion of property damage and decontamination liability. Coverage is also provided for the cost of replacement power, which includes indemnity payments for up to three years, after a waiting period of 17 weeks. Coverage is provided primarily through mutual insurance companies owned by utilities with nuclear facilities. If losses at any of the nuclear facilities covered by the risk-sharing arrangements were to exceed the accumulated funds available from these insurance programs, SDG&E could be assessed retrospective premium adjustments of up to $6 million.
Department of Energy Decommissioning The Energy Policy Act of 1992 established a fund for the decontamination and decommissioning of the Department of Energy nuclear-fuel-enrichment facilities. Utilities using the DOE services are contributing a total of $2.3 billion, subject to adjustment for inflation, over a 15-year period ending in 2006. Each utility's share is based on its share of enrichment services purchased from the DOE. SDG&E's annual contribution is $1 million, and will be recovered as part of decommissioning costs (see Note 10).
Litigation Enova and its subsidiaries, including SDG&E, are involved in various legal matters, including those arising out of the ordinary course of business. Management believes that these matters will not have a material adverse effect on Enova's results of operations, financial condition or liquidity.
Distribution System Conversion Under a CPUC-mandated program and through franchise agreements with various cities, SDG&E is committed, in varying amounts, to convert overhead distribution facilities to underground. As of December 31, 1997, the aggregate unexpended amount of this commitment was approximately $100 million. Capital expenditures for underground conversions were $17 million in 1997, $15 million in 1996 and $12 million in 1995.
Concentration of Credit Risk SDG&E grants credit to its utility customers, substantially all of whom are located in its service territory, which covers all of San Diego County and an adjacent portion of Orange County.
NOTE 10: INDUSTRY RESTRUCTURING In September 1996, the state of California enacted a law restructuring California's electric-utility industry (AB 1890). The legislation adopts the December 1995 CPUC policy decision restructuring the industry to stimulate competition and reduce rates. The new law supersedes the CPUC policy decision when in conflict. Beginning on March 31, 1998, customers will be able to buy their electricity through a power exchange that will obtain power from qualifying facilities, nuclear units and, lastly, from the lowest- bidding suppliers. The power exchange will serve as a wholesale power pool allowing all energy producers to participate competitively. An Independent System Operator will schedule power transactions and access to the transmission system. Consumers also may choose either to continue to purchase from their local utility under
regulated tariffs or to enter into private contracts with generators, brokers or others. The local utility will continue to provide distribution service regardless of which source the consumer chooses. Utilities are allowed a reasonable opportunity to recover their stranded costs through December 31, 2001. Stranded costs, such as those related to reasonable employee-related costs directly caused by restructuring and purchased-power contracts (including those with qualifying facilities), may be recovered beyond December 31, 2001. Outside of those exceptions, stranded costs not recovered through 2001 will not be collected from customers. Such costs, if any, would be written off as a charge against earnings. SDG&E's transition cost application filed in October 1996 identifies costs totaling $2 billion (net present value in 1998 dollars). These identified transition costs were determined to be reasonable by independent auditors selected by the CPUC, with $73 million requiring further action before being deemed recoverable transition costs. Of this amount, the CPUC has excluded from transition cost recovery $39 million in fixed costs relating to gas transportation to power plants, which SDG&E believes will be recovered through contracts with the ISO. Total transition costs include sunk costs, as well as ongoing costs the CPUC finds reasonable and necessary to maintain generation facilities through December 31, 2001. Both the CPUC policy decision and AB 1890 provide that above-market costs for existing purchased-power contracts may be recovered over the terms of the contracts or sooner. Qualifying facilities purchases include approximately 100 existing contracts, which extend as far as 2025. Other power purchases consist of two long-term contracts expiring in 2001 and 2013. Transition costs also include other items SDG&E has accrued under cost-of-service regulation. Nuclear decommissioning costs are nonbypassable until fully recovered, but are not included as part of transition costs. Through December 31, 1997, SDG&E has recovered transition costs of $0.2 billion for nuclear generation and $0.1 billion for nonnuclear generation. Additionally, overcollections of $0.1 billion recorded in the ECAC and ERAM balancing accounts as of December 31, 1997, have been applied to transition cost recovery, leaving approximately $1.6 billion for future recovery. Included therein is $0.4 billion for post-2001 purchased-power-contract payments that may be recovered after 2001, subject to an annual reasonableness review. SDG&E has announced a plan to auction its power plants and other electric-generating assets. This plan includes the divestiture of SDG&E's fossil power plants and combustion turbines, its 20-percent interest in SONGS and its portfolio of long-term purchased-power contracts. The power plants, including the interest in SONGS, have a net book value as of December 31, 1997, of $800 million ($200 million for fossil and $600 million for SONGS). The proceeds from the auction will be applied directly to SDG&E's transition costs. In December 1997, SDG&E filed with the CPUC for its approval of the auction plan. The sale of the nonnuclear-generating assets is expected to be completed by the end of the first quarter of 1999. During the 1998-2001 period, recovery of transition costs is limited by the rate freeze (discussed below). Management believes that the rates within the rate cap and the proceeds from the sale of electric-generating assets will be sufficient to recover all of SDG&E's approved transition costs by December 31, 2001. The California legislation provides for a 10-percent reduction of residential and small commercial customers' rates, which began in January 1998, as a result of the utilities' receiving the proceeds of rate-reduction bonds issued by an agency of the state of California. In December 1997, $658 million of rate-reduction bonds were issued on behalf of SDG&E at an average interest rate of 6.26 percent. These bonds are being repaid over 10 years by SDG&E's residential and small- commercial customers via a nonbypassable charge on their electric bills. In addition, the California legislation includes a rate freeze for all customers. Until the earlier of March 31, 2002, or when transition cost recovery is complete, SDG&E's system-average rate will be frozen at June 1996 levels (9.64 cents per kwh), except for the impact of fuel cost changes and the 10-percent rate reduction described above. Beginning in 1998 system-average rates cannot be increased above 9.43 cents per kwh, which includes the mandatory rate reduction and any impact of fuel cost changes.
As discussed in Note 2, SDG&E has been accounting for the economic effects of regulation in accordance with SFAS No. 71. The SEC indicated a concern that the California investor-owned utilities may not meet the criteria of SFAS No. 71 with respect to their electric-generation net regulatory assets. SDG&E has ceased the application of SFAS No. 71 to its generation business, in accordance with the conclusion by the Emerging Issues Task Force of the Financial Accounting Standards Board that the application of SFAS 71 should be discontinued when deregulatory legislation is issued that determines that a portion of an entity's business will no longer be regulated. The discontinuance of SFAS No. 71 applied to the utilities' generation business did not result in a write- off of their net regulatory assets, since the CPUC has approved the recovery of these assets by the distribution portion of their business, subject to the rate cap.
Item 8. Financial Statements and Supplementary Data - San Diego Gas & Electric Company
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of San Diego Gas & Electric Company:
We have audited the accompanying consolidated balance sheets of San Diego Gas & Electric Company and subsidiary as of December 31, 1997 and 1996, and the related statements of consolidated income, consolidated changes in capital stock and retained earnings, and consolidated cash flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company'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, such consolidated financial statements present fairly, in all material respects, the financial position of San Diego Gas & Electric Company and subsidiary 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.
/S/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP San Diego, California February 23, 1998
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
SAN DIEGO GAS & ELECTRIC COMPANY
Except as modified below, the Notes to Consolidated Financial Statements of Enova Corporation are incorporated herein by reference insofar as they relate to San Diego Gas & Electric Company:
Note 1 -- Business Combination Note 2 -- Significant Accounting Policies Note 4 -- Long-Term Debt Note 5 -- Facilities Under Joint Ownership Note 6 -- Employee Benefit Plans Note 8 -- Financial Instruments Note 9 -- Contingencies and Commitments Note 10 -- Industry Restructuring
Note 3: Significant Affiliate Transactions
In January 1996 Enova Corporation (Enova) became the parent of San Diego Gas & Electric (SDG&E) and its subsidiaries. At that time SDG&E's ownership interests in its subsidiaries were transferred to Enova at book value. SDG&E's financial statements for periods prior to 1996 reflect the results of these subsidiaries as discontinued operations in accordance with Accounting Principles Board Opinion No. 30 "Reporting the Effects of a Disposal of a Segment of Business." Discontinued operations are summarized in the table below:
Year Ended December 31, - ------------------------------------------------------ (millions of dollars)
Revenues $81 Loss from operations before income taxes (24) Loss on disposal before income taxes (12) Income tax benefits 32 - ------------------------------------------------------
In December 1997 SDG&E and Enova signed a promissory note agreement for an amount not to exceed $400 million to be loaned by SDG&E to Enova due within one year. Interest on the outstanding balance under the note is accrued monthly at the current three-month commercial paper rate. As of December 31, 1997 $130 million had been issued and was outstanding under the promissory note agreement.
In March 1997 SDG&E paid to Enova a special dividend of $70 million to be used for the repurchase of three million shares of Enova common stock.
Note 4: Long-Term Debt
The information contained in Enova Corporation's Statements of Consolidated Long-Term Debt is incorporated herein by reference.
Note 7: Income Taxes
SDG&E's income tax payments totaled $217 million in 1997, $245 million in 1996 and $200 million in 1995.
The components of accumulated deferred income taxes at December 31 are as follows:
in thousands of dollars 1997 1996 - ------------------------------------------------------------------ Deferred tax liabilities Differences in financial and tax bases of utility plant $567,804 $628,617 Loss on reacquired debt 30,535 26,399 Other 65,675 63,081 - ------------------------------------------------------------------ Total deferred tax liabilities 664,014 718,097 - ------------------------------------------------------------------ Deferred tax assets Unamortized investment tax credits 64,873 68,239 Regulatory balancing accounts 27,903 37,010 Unbilled revenue 22,365 21,923 Other 90,232 123,534 - ------------------------------------------------------------------ Total deferred tax assets 205,373 250,706 - ------------------------------------------------------------------ Net deferred income tax liability 458,641 467,391 Current portion (net asset) 13,249 19,728 - ------------------------------------------------------------------ Non-current portion (net liability) $471,890 $487,119 ==================================================================
The components of income tax expense are as follows:
in thousands of dollars 1997 1996 1995 - --------------------------------------------------------------- Current Federal $164,642 $169,309 $170,212 State 43,801 45,018 44,863 - -------------------------------------------------------------- Total current taxes 208,443 214,327 215,075 - -------------------------------------------------------------- Deferred Federal 12,922 (8,666) (23,647) State 1,600 (1,518) (13,464) - -------------------------------------------------------------- Total deferred taxes 14,522 (10,184) (37,111) - -------------------------------------------------------------- Deferred investment tax credits - net (3,809) (6,185) (4,935) - -------------------------------------------------------------- Total income tax expense $219,156 $197,958 $173,029 ==============================================================
Federal and state income taxes are allocated between operating income and other income.
The reconciliation of the statutory federal income tax rate to effective income tax rate is as follows:
1997 1996 1995 - ------------------------------------------------------------- Statutory federal income tax rate 35.0% 35.0% 35.0% Depreciation 7.1 5.7 5.0 State income taxes - net of federal income tax benefit 5.7 6.1 4.8 Tax credits (1.3) (2.1) (1.8) Repair allowance (1.6) (1.1) (2.8) Other - net 3.0 3.4 3.9 - ------------------------------------------------------------- Effective income tax rate 47.9% 47.0% 44.1% =============================================================
Note 11: Capital Stock
The information contained in SDG&E's Statements of Changes in Capital Stock and Retained Earnings is incorporated herein by reference. The information contained in Enova Corporation's Statements of Consolidated Capital Stock as it relates to preferred and preference stock is incorporated herein by reference.
Note 12: Segments of Business
The information contained in Enova Corporation's Statements of Consolidated Financial Information by Segments of Business is incorporated herein by reference.
Note 13: Quarterly Financial Data (Unaudited) SAN DIEGO GAS & ELECTRIC
Item 9.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure - Enova Corporation/San Diego Gas & Electric Company None.
PART III
Item 10.
Item 10. Directors and Executive Officers of the Registrant
Enova Corporation
The information required on Identification of Directors is incorporated by reference from "Election of Directors" in the March 1998 Enova Corporation Proxy Statement. The information required on executive officers is incorporated by reference from Item 4 herein.
San Diego Gas & Electric Company
The information required on Identification of Directors is incorporated by reference from "Election of Directors" in the March 1998 SDG&E Proxy Statement. The information required on executive officers is incorporated by reference from Item 4 herein.
Item 11.
Item 11. Executive Compensation
Enova Corporation
The information required by Item 11 is incorporated by reference from "Executive Compensation and Transactions with Management and Others" in the March 1998 Enova Corporation Proxy Statement.
San Diego Gas & Electric Company
The information required by Item 11 is incorporated by reference from "Executive Compensation and Transactions with Management and Others" in the March 1998 SDG&E Proxy Statement.
Item 12.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Enova Corporation
The information required by Item 12 is incorporated by reference from "Security Ownership of Management and Certain Beneficial Holders" in the March 1998 Enova Corporation Proxy Statement.
San Diego Gas & Electric Company
The information required by Item 12 is incorporated by reference from "Security Ownership of Management and Certain Beneficial Holders" in the March 1998 SDG&E Proxy Statement.
Item 13.
Item 13. Certain Relationships and Related Transactions None.
PART IV - Enova Corporation/San Diego Gas & Electric Company:
Item 14.
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) The following documents are filed as part of this report:
1. Financial statements Enova Corporation SDG&E
Independent Auditors' Report . . . . . . . . . . . . . 57 78
Statements of Income for the years ended December 31, 1997, 1996 and 1995. . . . . . . . . . . 47 74
Balance Sheets at December 31, 1997 and 1996 . . . . . 48 75
Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995. . . . . . . . 49 76
Statements of Changes in Capital Stock and Retained Earnings for the years ended December 31, 1997, 1996 and 1995. . . . . . . . . . . 50 77
Statements of Capital Stock at December 31, 1997 and 1996. . . . . . . . . . . . . . 51 --
Statements of Long-Term Debt at December 31, 1997 and 1996. . . . . . . . . . . . . . 52 --
Statements of Financial Information by Segments of Business for the years ended December 31, 1997, 1996 and 1995. . . . . . . . . . . 54 --
Notes to Financial Statements. . . . . . . . . . . . . 58 79
Quarterly Financial Data (Unaudited) . . . . . . . . . 55 82
2. Financial statement schedules
The following documents may be found in this report at the indicated page numbers.
Report of Independent Auditors on Supplemental Schedule and Consent. . . . . . . . . . . . . . . . . . . . 86 Schedule I--Condensed Financial Information of Parent. . . . . 87
Schedules I through V, inclusive, except those referred to above, are omitted as not required or not applicable.
3. Exhibits
See Exhibit Index on page 90 of this report.
(b) Reports on Form 8-K
A Current Report on Form 8-K was filed on July 17, 1997 to announce the California Public Utilities Commission's decision on Southern California Gas Company's Performance-Based Ratemaking proceeding.
A Current Report on Form 8-K was filed on August 12, 1997 to announce the agreement for the joint acquisition of AIG Trading Corporation (now Sempra Energy Trading) by Enova Corporation and Pacific Enterprises, and the extension of the Enova Corporation and Pacific Enterprises merger agreement.
A Current Report on Form 8-K was filed on November 26, 1997 to announce the plans of San Diego Gas & Electric to auction its electric generation assets.
A Current Report on Form 8-K was filed on December 23, 1997 to announce the changes in the boards of directors and executive officers at Enova Corporation and San Diego Gas & Electric.
INDEPENDENT AUDITORS' CONSENT AND REPORT ON SCHEDULE
To the Shareholders and Boards of Directors of Enova Corporation and San Diego Gas & Electric Company:
We consent to the incorporation by reference in Post-Effective Amendment No. 2 to Registration Statement No. 33-59681 on Form S-3 and Post- Effective Amendment No. 1 to Registration Statement Nos. 33-59683 and 33-7108 on Form S-8 of Enova Corporation; in Registration Statement Nos. 33-45599, 33-52834 and 33-49837 on Form S-3 of San Diego Gas & Electric Company; in Registration Statement No. 333-30761 on Form S-3 of SDG&E Funding LLC; and in Registration Statement No. 333-21229 on Form S-4 of Mineral Energy Company of our reports dated February 23, 1998 on Enova Corporation and San Diego Gas & Electric Company, appearing in this Annual Report on Form 10-K of Enova Corporation and San Diego Gas & Electric Company for the year ended December 31, 1997.
Our audits of the financial statements referred to in our aforementioned reports also included the financial statement schedule of Enova Corporation, listed in Item 14. This financial statement schedule is the responsibility of the management of Enova Corporation. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic Enova Corporation financial statements taken as a whole, presents fairly in all material respects the information set forth therein.
/S/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP San Diego, California February 23, 1998
Schedule I -- CONDENSED FINANCIAL INFORMATION OF PARENT