SEC Filing | Sempra

SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K (Mark One) [X] Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the fiscal year ended December 31, 1998 -------------------- OR [ ] Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period from to - ------ ------- SAN DIEGO GAS & ELECTRIC COMPANY - ------------------------------------------------------------------- (Exact name of registrant as specified in its charter) CALIFORNIA 1-3779 95-1184800 - ------------------------------------------------------------------- (State of incorporation (Commission (I.R.S. Employer or organization) File Number) Identification No. 8326 CENTURY PARK COURT, SAN DIEGO, CALIFORNIA 92123 - ------------------------------------------------------------------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (619)696-2000 -------------- SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Name of each exchange Title of each class on which registered - ------------------- --------------------- Preference Stock (Cumulative) American Without Par Value (except $1.70 and $1.7625 Series) Cumulative Preferred Stock, $20 Par Value (except 4.60% Series) SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days. Yes [ X ] No [ ] Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [ ] Exhibit Index on page 68. Glossary on page 76. Aggregate market value of the voting preferred stock held by non- affiliates of the registrant as of March 26, 1999 was $22.9 million. Registrant's common stock outstanding as of March 26, 1999 was wholly owned by Enova Corporation. DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Information Statement prepared for the May 1999 annual meeting of shareholders are incorporated by reference into Part III. TABLE OF CONTENTS PART I Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 3 Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 18 Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . 18 Item 4. Submission of Matters to a Vote of Security Holders. . 19 Executive Officers of the Registrant . . . . . . . . . 19 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . . . 19 Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 20 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . 20 Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . 34 Item 8. Financial Statements and Supplementary Data. . . . . . 35 Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . 64 PART III Item 10. Directors and Executive Officers of the Registrant . . 64 Item 11. Executive Compensation . . . . . . . . . . . . . . . . 64 Item 12. Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . . . 65 Item 13. Certain Relationships and Related Transactions . . . . 65 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . . . . . . . . . . 65 Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 67 Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 68 Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 This report 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. The words "estimates," "believes," "expects," "anticipates," "plans" and "intends," variations of such words, and similar expressions, are intended to identify forward- looking statements that involve risks and uncertainties which could cause actual results to differ materially from those anticipated. These statements are necessarily based upon various assumptions involving judgments with respect to the future including, among others, local, regional, national and international economic, competitive, political and regulatory conditions and developments, technological developments, capital market conditions, inflation rates, interest rates, energy markets, weather conditions, business and regulatory or legal decisions, the pace of deregulation of retail natural gas and electricity industries, the timing and success of business development efforts, and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the Company. Accordingly, while the Company believes that the assumptions are reasonable, there can be no assurance that they will approximate actual experience, or that the expectations will be realized. Readers are urged to carefully review and consider the risks, uncertainties and other factors which affect the Company's business described in this annual report and other reports filed by the Company from time to time with the Securities and Exchange Commission. PART I ITEM 1. BUSINESS DESCRIPTION OF BUSINESS San Diego Gas & Electric Company (SDG&E or the Company) is an operating public utility which provides electric and natural gas service to San Diego County and southern Orange County. SDG&E is the principal subsidiary of Enova Corporation (Enova). Effective June 26, 1998, Enova and Pacific Enterprises (PE) combined to form Sempra Energy, a California-based Fortune 500 energy-services company (PE/Enova Business Combination). Southern California Gas Company (SoCalGas), the nation's largest natural gas distribution utility, is the principal subsidiary of PE. Further discussion of SDG&E and the PE/Enova Business Combination is included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 1 of the "Notes to Consolidated Financial Statements," herein. GOVERNMENT REGULATION Local Regulation SDG&E 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 natural gas in the streets and other public places. The franchises do not have fixed terms, except for the electric and natural gas franchises with the cities of Chula Vista (2003), Encinitas (2012), San Diego (2021) and Coronado (2028); and the natural gas franchises with the city of Escondido (2036) and the county of San Diego (2030). State Regulation The California Public Utilities Commission (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) 1998 1997 1996 - ------------------------------------------------------------------- Revenue by type of customer: Electric: Residential $ 637 $ 684 $ 647 Commercial/Industrial 876 948 886 Other 352 137 58 --------- --------- --------- Total Electric Revenues 1,865 1,769 1,591 --------- --------- --------- Gas: Residential 258 241 210 Commercial/Industrial 105 120 101 Utility Electric Generation 21 37 37 --------- --------- --------- Total Gas Revenues 384 398 348 --------- --------- --------- PX/ISO Power 500 -- -- --------- --------- --------- Total Utility Revenues $ 2,749 $ 2,167 $ 1,939 ========= ========= ========= Industry segment information is contained in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 13 of the "Notes to Consolidated Financial Statements" herein. NATURAL GAS OPERATIONS SDG&E distributes natural gas to 721,000 customers in San Diego and southern Orange counties throughout a 4,100-square-mile service territory. The Company purchases natural gas for resale to its customers and for fuel in its generating plants. Supplies of Natural Gas The Company buys natural gas primarily from various spot-market suppliers. It also has natural gas transportation contracts with pipeline companies, which expire at various dates through 2023. Most of the natural gas purchased and delivered by the Company is produced outside of California. 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. The rates that interstate pipeline companies may charge for natural gas and transportation services are regulated by the FERC. All natural gas is delivered to SDG&E under a transportation and storage agreement with SoCalGas. SDG&E has four long-term natural gas supply contracts with four Canadian suppliers. The Company has been in negotiations and litigation with the suppliers concerning the contracts' terms and prices. Of the four contracts, three have been settled. Additional information regarding natural gas contracts is provided in Note 11 of the "Notes to Consolidated Financial Statements" herein. During 1998, SDG&E received natural gas from one Canadian supplier based on terms of the settlement agreement. Natural gas from Canada is transported to SDG&E's system over Alberta Natural Gas, Pacific Gas Transmission and Pacific Gas & Electric (PG&E) pipelines. The following table shows the sources of natural gas deliveries from 1994 through 1998. Year Ended December 31 ------------------------------------------------------------------- 1998 1997 1996 1995 1994 - ------------------------------------------------------------------------------------------------------------- Gas Purchases (billions of cubic feet) 118 101 97 90 95 Customer-Owned and Exchange Receipts 19 18 17 17 15 Storage Withdrawal (Injection) - Net (3) 1 2 (1) Company Use and Unaccounted For (2) (1) (1) (1) (2) ------- ------- ------- ------- ------- Net Deliveries 132 119 113 108 107 ======= ======= ======= ======= ======= Cost of Gas Purchased (millions of dollars) $ 318 $ 311 $ 252 $ 188 $ 246 ------- ------- ------- ------- ------- Average Cost of Gas Purchased (Dollars per Thousand Cubic Feet) $2.69 $3.08 $2.59 $2.08 $2.60 ======= ======= ======= ======= ======= Market-sensitive natural gas supplies (supplies purchased on the spot market as well as under longer-term contracts based on spot prices) accounted for nearly 100 percent of total natural gas volumes purchased by the Company during the last five years. These supplies were generally purchased at prices significantly below those of long-term sources of supply. The Company provided transportation services for the customer-owned natural gas. The Company estimates that sufficient natural gas supplies will be available to meet the requirements of its customers for the next several years. Customers For regulatory purposes, customers are separated into core and noncore customers. Core customers are primarily residential and small commercial and industrial customers, without alternative fuel capability. There are 721,000 core customers (694,000 million residential and 27,000 small commercial and industrial). Noncore customers consist primarily of utility electric generation (UEG), wholesale, and large commercial and industrial customers, and total 113. Most core customers purchase natural gas directly from the Company. Core customers are permitted to aggregate their natural gas requirement and, up to a limit of 10 percent of the Company's core market, to purchase natural gas directly from brokers or producers. The Company continues to be obligated to purchase reliable supplies of natural gas to serve the requirements of its core customers. Noncore customers have the option of purchasing natural gas either from the Company or from other sources, such as brokers or producers, for delivery through the Company's transmission and distribution system. The only natural gas supplies that the Company may offer for sale to noncore customers are the same supplies that it purchases for its core customers. Most noncore customers procure their own natural gas supply. For 1998, approximately 90 percent of the CPUC-authorized natural gas margin was allocated to the core customers, with 10 percent allocated to the noncore customers. Although revenue from transportation services is less than for natural gas sales, the Company generally earns the same margin whether the Company buys the gas and sells it to the customer or transports natural gas already owned by the customer. Demand for Natural Gas Natural gas is a principal energy source for residential, commercial, industrial and UEG customers. Natural gas competes with electricity for residential and commercial cooking, water heating, space heating and clothes drying, and with other fuels for large industrial, commercial and UEG uses. Growth in the natural gas markets is largely dependent upon the health and expansion of the southern California economy. The Company added approximately 12,000 new natural gas customers in 1998. This represents a growth rate of approximately 1.6 percent. The Company expects its growth for 1999 will continue at about the 1998 level. Demand for natural gas by noncore customers is very sensitive to the price of alternative competitive fuels. Although the number of noncore customers in 1998 was only 113, they accounted for approximately 32 percent of the authorized natural gas revenues and 64 percent of total natural gas volumes. External factors such as weather, electric deregulation, the increased use of hydro-electric power, competing pipeline bypass and general economic conditions can result in significant shifts in this market. Natural gas demand for the Company's generation plants is also greatly affected by the price and availability of electricity. Other Additional information concerning customer demand and other aspects of natural gas operations is provided under "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 11 of the "Notes to Consolidated Financial Statements" herein. ELECTRIC OPERATIONS Resource Planning In September 1996, California enacted a law restructuring California's electric-utility industry. The legislation adopted the December 1995 CPUC policy decision restructuring the industry to stimulate competition and reduce rates. Beginning on March 31, 1998, customers were given the opportunity to choose to continue to purchase their electricity from the local utility under regulated tariffs, to enter into contracts with other energy-service providers (direct access) or to buy their power from the independent Power Exchange (PX) that serves as a wholesale power pool allowing all energy producers to participate competitively. Additional information concerning electric-industry restructuring is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 11 and 12 of the "Notes to Consolidated Financial Statements" herein. Electric Resources In connection with electric-industry restructuring, beginning March 31, 1998, the California investor-owned utilities (IOUs) are obligated to bid their power supply, including owned generation and purchased-power contracts, into the PX. The IOUs are also obligated to purchase from the PX the power that they distribute. Based on generating plants in service and purchased-power contracts currently in place, at February 28, 1999 the net megawatts (mw) of electric power available to SDG&E to bid into the PX 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 275 Contracts with others 593 ----- Total 3,271 ===== SDG&E reported an all-time record for electricity usage of 3,960 mw on August 31, 1998. The previous record of 3,668 mw was reached on September 4, 1997. Gas/Oil Generating Plants: In connection with electric-industry restructuring, in December 1998, SDG&E entered into agreements for the sale of its South Bay and Encina power plants and 17 combustion turbines. The sales are subject to regulatory approval and are expected to close during the first half of 1999. 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 Units 2 and 3. Southern California Edison (Edison) owns the remaining interests and operates the units. SONGS Unit 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 Units 2 and 3 are also decommissioned. However, SDG&E and the other owners have requested that the CPUC grant authority to begin decommissioning Unit 1 on January 1, 2000. 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 Unit 1, and the unit was placed in a long-term storage condition in May 1994. SONGS Units 2 and 3 began commercial operation in August 1983 and April 1984, respectively. SDG&E's share of the capacity is 214 mw of Unit 2 and 216 mw of Unit 3. During 1998 SDG&E spent $14 million on capital modifications and additions and expects to spend $11 million in 1999. SDG&E deposits funds in an external trust to provide for the future dismantling and decontamination of the units. Additional Information: Additional information concerning SDG&E's power plants, the SONGS units, nuclear decommissioning and industry restructuring (including SDG&E's divestiture of its electric generation assets) is provided immediately below and in "Environmental Matters" and "Electric Properties," herein, as well as in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 5, 11 and 12 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 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 275 ===== Contracts with Others: Illinova Power Marketing Through December 1999 200 System Supply LG&E Power Marketing Through December 2001 150 System Supply Applied Energy Through December 2019 102 Cogeneration Yuma Cogeneration Through June 2024 50 Cogeneration Goal Line Limited Through December 2025 50 Cogeneration Partnership Other (89) Various 41 Cogeneration ------ Total 593 ====== Under the contracts with PGE and PNM, SDG&E pays a capacity charge plus a charge based on the amount of energy received. 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 "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 11 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. 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 the Independent System Operator (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 (see "Transmission Access" 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 IOUs of their transmission facilities to the ISO. Beginning on March 31, 1998 the ISO is 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. 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 - ------------------------------------------------------------------- 1998 1997 1996 1998 1997 1996 ----- ----- ----- ---- ---- ---- Natural gas 17.3% 19.8% 22.8% 3.0 3.3 2.8 Nuclear fuel 11.5 11.8 19.6 0.6 0.6 0.5 Fuel oil 0.1 1.1 2.4 2.2 ----- ----- ----- Total generation 28.8 31.7 43.5 Purchased power - net 26.3 68.3 56.5 3.6 2.8 3.1 ISO/PX 44.9 3.4 ----- ----- ----- 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 $0.90 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 11 of the "Notes to Consolidated Financial Statements" herein. RATES AND REGULATION SDG&E is regulated by the CPUC, which consists of five commissioners appointed by the Governor of California for staggered six-year terms. Two of the five commissioner positions are currently vacant. It is the responsibility of the CPUC to determine that utilities operate within the best interests of their customers. The regulatory structure is complex and has a substantial impact on the profitability of the Company. Both the electric and natural gas industries are currently undergoing transitions to competition (see below). Electric Industry Restructuring In September 1996, California enacted a law restructuring its electric-utility industry. The legislation adopts the December 1995 CPUC policy decision restructuring the industry to stimulate competition and reduce rates. Additional information on electric industry restructuring is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 12 of the "Notes to Consolidated Financial Statements" herein. Natural Gas Industry Restructuring The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. In January 1998, the CPUC released a staff report initiating a project to assess the current market and regulatory framework for California's natural gas industry. The general goals of the plan are to consider reforms to the current regulatory framework emphasizing market-oriented policies benefiting California natural gas customers. Additional information on natural gas industry restructuring is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 12 of the "Notes to Consolidated Financial Statements" herein. Balancing Accounts Previously, earnings fluctuations from changes in the costs of electric fuel, purchased energy and natural gas, and consumption levels for electricity and the majority of natural gas were eliminated by balancing accounts authorized by the CPUC. This is still the case for most natural gas operations. However, as a result of California's electric restructuring law, overcollections recorded in the electric balancing accounts were applied to transition cost recovery, and fluctuations in costs and consumption levels can affect earnings from electric operations. 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 Regulation (PBR) To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC has been directing utilities to use PBR. PBR has replaced the general rate case and certain other regulatory proceedings for SDG&E. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and productivity measures, as well as cost reductions, rather than relying solely on expanding utility rate base in a market where a utility already has a highly developed infrastructure. Additional information on PBR is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 12 of the "Notes to Consolidated Financial Statements" herein. Biennial Cost Allocation Proceeding (BCAP) Rates to recover the changes in natural gas fuel costs and changes in the cost of natural gas transportation services are determined in the BCAP. The BCAP adjusts rates to reflect variances in core customer demand from estimates previously used in establishing core customer rates. The mechanism substantially eliminates the effect on core income of variances in core market demand and natural gas costs. Additional information on the BCAP is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 12 of the "Notes to Consolidated Financial Statements" herein. Affiliate Transactions In December 1997, the CPUC adopted rules establishing uniform standards of conduct governing the manner in which California investor-owned utilities conduct business with their affiliates. The objective of these rules is to ensure that the utilities' energy affiliates do not gain an unfair advantage over other competitors in the marketplace and that utility customers do not subsidize affiliate activities. Additional information on affiliate transactions is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 12 of the "Notes to Consolidated Financial Statements" herein. Cost of Capital Under PBR, annual Cost of Capital proceedings have been replaced by an automatic adjustment mechanism if changes in certain indices exceed established tolerances. SDG&E is seeking CPUC approval to establish new, separate rates of return for SDG&E's electric- distribution and natural gas businesses. A CPUC decision is expected during the second quarter of 1999. In 1998, SDG&E's natural gas and electric-distribution operations were authorized to earn a rate of return on common equity of 11.6 percent and a rate of return on rate base of 9.35 percent. Additional information on the utility's cost of capital is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 12 of the "Notes to Consolidated Financial Statements" herein. ENVIRONMENTAL MATTERS Discussions about environmental issues affecting SDG&E, including hazardous substances and air 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 The utility lawfully disposed of 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. Under California law, redevelopment agencies are authorized to require landowners to cleanup property within their jurisdiction or, where the landowner or operator of such a facility fails to complete any corrective action required, applicable environmental laws may impose an obligation to undertake corrective actions on the utility and others who disposed of hazardous wastes at the facility. The Redevelopment Agency for the City of San Diego has exerted this authority affecting the Company's Station A facility and adjacent properties to accommodate a major league ballpark and ancillary development proposed by the City. During the early 1900s, SDG&E and its predecessors manufactured gas from coal and oil at the Station A facility and at two small facilities in Escondido and Oceanside. Environmental assessments have identified residual by-products from the gas-manufacturing process and subsurface hydrocarbon contamination on portions of the Station A site. A risk assessment has been completed for Station A and demolition was performed during 1997 at a cost of $1 million. Initial cleanup actions commenced in 1998, and are expected to be completed in 1999, at an estimated cost of $5 million. SDG&E is negotiating with the agency to create a cooperative agreement as a result of which the Station A cleanup will be performed under the oversight of the San Diego County Department of Environmental Health, though the agency will retain its rights to enforce the cleanup in the event SDG&E does not complete it. Contaminants resulting from the gas-manufacturing process by-products were assessed at the Escondido and Oceanside sites. Remediation at the Escondido site has been completed and a site-closure letter received. Remediation at the Oceanside facility is in process and the cost is not expected to be significant. Station B is located in downtown San Diego and was operated as a steam and electric-generating facility between 1911 and June 1993 when it was closed. 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. Asbestos was used in the construction of the power plant. Activities to dismantle and decommission the facility required the removal of the asbestos in a manner complying with all applicable environmental, health and safety laws. This work also included the removal or cleanup of certain loose and flaking lead-based paints, small amounts of PCBs, fuel oil and other substances. These activities were completed in 1998 at a cost of $6 million. SDG&E is in the process of selling its electric-generating assets. As a part of its environmental due diligence, the utility conducted a thorough environmental assessment of the South Bay and Encina power plants and 17 combustion turbine sites to determine the environmental condition of each. Pursuant to the sale agreements for such facilities, the utility and the buyers have apportioned responsibility for such environmental conditions generally based on contamination existing at the time of transfer and the cleanup level necessary for the continued use of the sites for electric generation. While the sites are relatively clean, the assessments identified instances of contamination, principally hydrocarbon releases, some of which were determined to be significant and to require cleanup in accordance with the agreement. Estimated costs to perform the necessary remediation are $7 to $8 million at the South Bay power plant, $0.9 million at the Encina power plant, and $1.9 million at the combustion turbine sites. These costs will be offset against the sales price for the facilities, together with other appropriate costs, and the remaining net proceeds will be offset against SDG&E's other transition costs. SDG&E has been named as a potential responsible party (PRP) for an industrial waste disposal site as described below. SDG&E and 10 other entities have been named PRPs by the California Department of Toxic Substances Control (DTSC) as liable for any required corrective action regarding contamination at a site in Pico Rivera, California. DTSC has taken this action because the utility 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 $1 million. The estimate for the actual cleanup is in the $2 million to $8 million range. At December 31, 1998, the utility's estimated remaining investigation and remediation liability related to hazardous waste sites (non-PRP sites) was $15 million, of which 90 percent is authorized to be recovered through the Hazardous Waste Collaborative mechanism. SDG&E believes that any costs not ultimately recovered through rates, insurance or other means, upon giving effect to previously established liabilities, will not have a material adverse effect on the Company's consolidated results of operations or the financial position. Estimated liabilities for environmental remediation are recorded when amounts are probable and estimable. Amounts authorized to be recovered in rates under the Hazardous Waste Collaborative mechanism are recorded as a regulatory asset. Possible recoveries of environmental remediation liabilities from third parties are not deducted from the liability. Electric and Magnetic Fields (EMFs) Although scientists continue to research the possibility that exposure to EMFs causes adverse health effects, science, to date, has not demonstrated a 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 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 and Water Quality As mentioned above, SDG&E has entered into agreements for the sale of its fossil-fueled generating facilities. The completion of these sales will, for the most part, eliminate the potential impact of the following issues. 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. The estimated capital costs for compliance with the rule have decreased to an immaterial amount due to the sale of the electric- generating power plants. 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 Rule 69 compliance costs to increase. Wastewater discharge permits issued by the Regional Water Quality Control Board (RWQCB) for the utility's Encina and South Bay power plants are required to enable the utility 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 continuation of 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 the utility 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, intake structures 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 to evaluate the exception requests. The results of these additional studies were submitted to the RWQCB and the United States Environmental Protection Agency in 1997. If the utility's exception requests are denied, the utility could be required to construct offshore discharge facilities, or other structures at an estimated 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 the utility for the South Bay power plant. SDG&E filed an appeal to the State Water Resources Control Board (SWRCB) of various provisions, which the utility considered unduly stringent. Certain of these matters were resolved in negotiations among the RWQCB, the SWRCB and certain environmental groups. The SWRCB dismissed the remaining matters, which SDG&E thereafter appealed to the San Diego County Superior Court. These latter issues were subsequently settled through negotiations between SDG&E and the RWQCB. All of the settled issues have been incorporated into the November 1996 National Pollutant Discharge Elimination System permit by permit addendums adopted by the RWQCB. The Superior Court case will be dismissed after the expiration of the RWQCB appeal and EPA review periods. 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. In May 1987 the RWQCB issued SDG&E a cleanup and abatement order for gasoline contamination originating from an underground storage tank located at the utility'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 RWQCB. OTHER Year 2000 A discussion of the Company's plans to prepare its 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. Research, Development and Demonstration (RD&D) As a result of electric-industry restructuring, SDG&E has significantly reduced its electric RD&D program. Effective January 1, 1998, the CEC began administering the electric public purpose RD&D programs to which SDG&E contributes $3.9 million annually. In December 1998, the CPUC approved SDG&E's $1.2 million request to fund natural gas RD&D programs. SDG&E will use these revenues to fund gas projects that add value to the utility and its customers. Annual RD&D costs have averaged $5.2 million over the past three years. Employees of Registrant As of December 31, 1998, SDG&E had 2,982 employees, compared to 3,576 at December 31, 1997. This decrease is related to synergies resulting from the PE/Enova Business Combination and the shifting of certain functions to Sempra Energy. Certain employees at SDG&E are represented by the International Brotherhood of Electrical Workers, Local 465, with two labor agreements. The generation contract runs through February 28, 2001 and negotiations for the utility contract (transmission and distribution) are ongoing. ITEM 2. PROPERTIES Electric Properties The utility's generating capacity is described in "Electric Resources" herein. 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. 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, 167 miles of high pressure transmission pipelines, 6,858 miles of high and low pressure distribution mains, and 5,695 miles of service lines. Other Properties SDG&E 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. SDG&E owns or leases other offices, operating and maintenance centers, shops, service facilities, and certain equipment necessary in the conduct of business. ITEM 3. LEGAL PROCEEDINGS Except for the matters referred to in the financial statements in Item 8 or referred to elsewhere in this Annual Report, neither the Company nor any of its affiliates is a party to, nor is its property the subject of, any material pending legal proceedings other than routine litigation incidental to its businesses. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None ITEM 4. EXECUTIVE OFFICERS OF THE REGISTRANT Name Age* Positions - ------------------------------------------------------------------- Warren I. Mitchell 61 Chairman Edwin A. Guiles 49 President and Chief Financial Officer Gary D. Cotton 58 Senior Vice President - Fuels & Power Operations Steven D. Davis 42 Vice President and Corporate Secretary Pamela J. Fair 40 Vice President - Marketing & Customer Services * As of December 31, 1998. Each Executive Officer has been an officer of Sempra Energy or one of its subsidiaries for more than five years. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS All of the issued and outstanding common stock of SDG&E is owned by Enova, a wholly owned subsidiary of Sempra Energy. The information required by Item 5 concerning dividends declared is included in the "Statements of Consolidated Changes in Shareholders' Equity" set forth in Item 8 of this Annual Report herein. Dividend Restrictions The CPUC regulates SDG&E's capital structure, limiting the dividends it may pay. At December 31, 1998, $183 million of retained earnings was available for future dividends. ITEM 6. SELECTED FINANCIAL DATA (Dollars in millions) At December 31, or for the years then ended ------------------------------------------------ 1998 1997 1996 1995 1994 -------- ------- ------- ------- ------- Income Statement Data: Operating Revenues $2,749 $2,167 $1,939 $1,814 $1,857 Operating Income $ 286 $ 317 $ 309 $ 315 $ 303 Dividends on Preferred Stock $ 6 $ 6 $ 6 $ 8 $ 8 Earnings Applicable to Common Shares $ 185 $ 232 $ 216 $ 226 $ 136 Balance Sheet Data: Total Assets $4,257 $4,654 $4,161 $4,473 $4,353 Long-Term Debt $1,548 $1,788 $1,285 $1,217 $1,214 Short-Term Debt (a) $ 72 $ 73 $ 34 $ 124 $ 182 Shareholders' Equity $1,227 $1,490 $1,508 $1,639 $1,593 (a) Includes bank and other notes payable, commercial paper borrowings and long- term debt due within one year. Since San Diego Gas & Electric Company is a wholly owned subsidiary of Enova Corporation, per share data has been omitted. This data should be read in conjunction with the consolidated financial statements and notes to consolidated financial statements contained herein. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Introduction This section includes management's analysis of operating results from 1996 through 1998, and is intended to provide additional information about the capital resources, liquidity and financial performance of San Diego Gas & Electric (SDG&E or the Company). This section also focuses on the major factors expected to influence future operating results and discusses investment and financing plans. It should be read in conjunction with the Consolidated Financial statements included in this Annual Report. The Company is an operating public utility engaged in the electric and natural 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. SDG&E's only subsidiary is described below under "Electric Rates." Business Combinations Sempra Energy (Sempra) was formed to serve as a holding company for SDG&E's parent, Enova Corporation (Enova), and Pacific Enterprises (PE), the parent company of Southern California Gas Company (SoCalGas) in connection with a business combination that became effective on June 26, 1998 (the PE/Enova Business Combination). Expenses incurred by SDG&E in connection with the business combination are $35 million, aftertax, and $11 million, aftertax, for the years ended December 31, 1998 and 1997, respectively. These costs consist primarily of employee-related costs, and investment banking, legal, regulatory and consulting fees. In connection with the PE/Enova Business Combination, the holders of common stock of Enova and PE each became holders of Sempra Energy common stock. PE's common shareholders received 1.5038 shares of Sempra Energy's common stock for each share of PE common stock, and Enova's common shareholders received one share of Sempra Energy's common stock for each share of Enova common stock. The combination was approved by the shareholders of both companies on March 11, 1997 and was a tax-free transaction. Capital Resources and Liquidity The Company's working capital requirements are met through cash from operations and the issuance of short-term and long-term debt. Additional information on sources and uses of cash during the last three years is summarized in the following condensed statement of cash flows: Sources and (Uses) of Cash Year Ended December 31, (Dollars in millions) 1998 1997 1996 - ------------------------------------------------------------------- Operating activities $ 535 $ 381 $ 529 ---------------------------------- Investing activities: Capital expenditures (227) (197) (209) Other - net (50) (17) (25) ---------------------------------- Total investing activities (277) (214) (234) ---------------------------------- Financing activities: Dividends paid (269) (256) (189) Long-term debt - net (241) 544 (31) Redemption of preferred stock -- -- (15) ---------------------------------- Total financing activities (510) 288 (235) ---------------------------------- Increase (decrease) in cash and cash equivalents $(252) $ 455 $ 60 - ------------------------------------------------------------------- Cash Flows from Operating Activities The increase in cash flows from operating activities in 1998 was primarily due to the acceleration of depreciation of electric- generating assets, partially offset by recovery of stranded costs via the competition transition charge and the 10-percent rate reduction reflected in customers' bills. The increase was also partially offset by expenses incurred in connection with the PE/Enova Business Combination. The decrease in cash flows from operating activities in 1997 was primarily due to increased working capital requirements. Cash Flows from Investing Activities Capital expenditures were $30 million higher in 1998 than in 1997 due to increased spending for system integrity and reliability projects, restoration of service and mandated programs. Capital expenditures were $12 million lower in 1997 than in 1996 due to changes in scope and timing of several major capital projects. Payments to the nuclear-decommissioning trusts are expected to continue until San Onofre Nuclear Generating Station (SONGS) is decommissioned, which is not expected to occur before 2013. Unit 1, although permanently shut down in 1992, was scheduled to be decommissioned concurrently with Units 2 and 3. However, the Company and the other SONGS owners have requested the CPUC for authority to begin decommissioning Unit 1 on January 1, 2000. See Note 5 of the notes to Consolidated Financial Statements for additional information. The decision of the CPUC approving the PE/Enova Business Combination required, among other things, that SDG&E divest itself of all its fossil-fueled generating facilities. In December 1998, SDG&E entered into agreements to accomplish that. Completion is pending regulatory approval and is expected during the first half of 1999. See "Electric-Generation Assets" below for further discussion. Anticipated proceeds from these plant assets, net of the assets' book value, the costs of sales and certain environmental cleanup costs, will be applied for accounting purposes directly to the recovery of the Company's other transition costs. On a cash basis, the proceeds will be available for general corporate purposes. However, the divestiture of the facilities will eventually lead to reduced cash flow from operations. Capital expenditures are estimated to be $240 million in 1999. They will be financed primarily by internally generated funds and will largely represent investment in rate base. The level of capital expenditures in the next few years will depend heavily on the impacts of electric-industry restructuring and the timing and extent of expenditures to comply with environmental requirements. Cash Flows from Financing Activities Net cash used in financing activities increased in 1998 due to the issuance of Rate Reduction Bonds in 1997 (see "Long-Term Debt" below) and greater long-term debt repayments in 1998. Net cash provided by financing activities increased in 1997 primarily due to issuance of the Rate Reduction Bonds partially offset by higher dividends paid. Long-Term Debt In December 1997, $658 million of Rate Reduction Bonds were issued on the Company's behalf at an average interest rate of 6.26 percent. A portion of the bond proceeds was used to retire variable-rate, taxable IDBs. Additional information concerning the Rate Reduction Bonds is provided below under "Electric Industry Restructuring." In 1998, cash was used for the repayment of $147 million of first mortgage bonds and $66 million of rate reduction bonds. In 1997, cash was used for the repayment of $127 million of first mortgage bonds. This was more than offset by the issuance of $25 million in Medium-Term Notes and $658 million of Rate Reduction Bonds. SDG&E has $83 million of temporary investments that will be maintained into the future to offset, for regulatory purposes, a like amount of long-term debt. The specific debt series being offset consist 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 are being maintained will be reduced below $83 million and the level of IDBs being offset will be reduced by the same amount. Dividends Common stock dividends amounted to $269 million, $256 million and $189 million in 1998, 1997 and 1996, respectively. The payment of future dividends and the amount thereof are within the discretion of the board of directors. Capitalization The debt-to-capitalization ratio was 57 percent at year-end 1998, above the 56 percent ratio in 1997. The increase was primarily due to the declaration of dividends to Enova. The debt-to- capitalization ratio increase to 56 percent in 1997 from 48 percent in 1996 was primarily due to the issuance of Rate Reduction Bonds. Cash and Temporary Investments Cash and temporary investments were $284 million at December 31, 1998. The Company anticipates that cash required in 1999 for capital expenditures, dividends and debt payments will be provided by cash generated from operating activities and existing cash balances. In addition to cash from ongoing operations, the Company has multi-year credit agreements that permit term borrowing of up to $295 million. At December 31, 1998 all bank lines of credit were unused. For further discussion, see Note 3 of the notes to Consolidated Financial statements. Ratemaking Procedures To understand the operations and financial results of the Company it is important to understand the ratemaking procedures that the Company follows. The Company is regulated by the CPUC. It is the responsibility of the CPUC to determine that utilities operate in the best interest of their customers and have the opportunity to earn a reasonable return on investment. In response to utility-industry restructuring, SDG&E received approval from the CPUC for performance-based regulation (PBR). PBR replaced the general rate case (GRC) procedure and certain other regulatory proceedings. Under ratemaking procedures in effect prior to PBR, the Company typically filed a GRC with the CPUC every three years. In a GRC, the CPUC establishes a base margin, which is the amount of revenue to be collected from customers to recover authorized operating expenses (other than the cost of fuel, natural gas and purchased power), depreciation, taxes and return on rate base. Under PBR, regulators allow income potential to be tied to achieving or exceeding specific performance and productivity measures, rather than relying solely on expanding utility rate base in a market where a utility already has a highly developed infrastructure. See additional discussion of PBR and electric- industry restructuring in Note 12 of the notes to Consolidated Financial Statements. Results of Operations 1998 Compared to 1997 Net income for 1998 decreased 20 percent to $191 million in 1998, compared to net income of $238 million in 1997. The decrease in net income was primarily due to higher PE/Enova Business Combination costs, lower incentive awards for performance-based ratemaking, and changes in regulatory mechanisms for recording revenues due to electric industry restructuring. Included in the calculation of pretax income are PE/Enova Business Combination costs of $35 million, aftertax, in 1998 and $11 million, aftertax, in 1997. These nonrecurring expenses consist primarily of employee-related costs, and investment banking, legal, regulatory and consulting fees. Electric revenues increased 5 percent in 1998 compared to 1997 primarily due to the recovery of stranded costs via the competition transition charge (CTC), and to alternate costs incurred (including fuel and purchased power) due to the delay from January 1 to March 31, 1998, in the startup of operations of the Power Exchange (PX) and the Independent System Operator (ISO). These factors were partially offset by a decrease in retail revenues as a result of the 10-percent small-customer rate reduction, which became effective in January 1998, and by a decrease in sales to other utilities, due to the startup of the PX. The 10-percent rate reduction and the PX are described under "Factors Influencing Future Performance" and in Note 12 of the notes to Consolidated Financial Statements. Revenues from the ISO/PX reflect sales from the Company's power plants and from long-term purchased-power contracts to the ISO/PX commencing April 1, 1998. Purchased power decreased 34 percent in 1998 primarily as a result of ISO/PX purchases' replacing short-term energy sources commencing April 1, 1998. Depreciation and amortization expense increased 86 percent in 1998 due to the recovery of stranded costs via the CTC. The financial impact of the increase is offset by CTC revenue (see above). Operating expenses increased 32 percent in 1998 primarily due to the higher PE/Enova Business Combination costs and higher electric-distribution maintenance costs primarily related to the Company's tree-trimming program. 1997 Compared to 1996 Net income for 1997 increased 7 percent to $238 million compared to net income of $222 million in 1996. The increase in earnings was primarily due to higher incentive awards for performance-based ratemaking and demand-side management, partially offset by the PE/Enova Business Combination costs. 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. Purchased power increased 42 percent in 1997, primarily due to increased volume, which resulted from lower nuclear-generation availability due to refuelings at SONGS and increased use of purchased power due to decreased purchased-power prices. The table below summarizes the components of electric volumes and revenues by customer class for 1998, 1997 and 1996. Electric Distribution (Dollars in millions, volumes in millions of Kwhrs) 1998 1997 1996 ---------------------------------------------------------- Volumes Revenue Volumes Revenue Volumes Revenue ---------------------------------------------------------- Residential 6,282 $ 637 6,125 $ 684 5,936 $ 647 Commercial 6,821 643 6,940 680 6,467 625 Industrial 3,097 233 3,607 268 3,567 261 Direct access 964 44 - - - - Street and highway lighting 85 8 76 7 75 7 Off-system sales 706 15 4,919 116 650 13 ---------------------------------------------------------- 17,955 1,580 21,667 1,755 16,695 1,553 Balancing and other 285 14 38 ---------------------------------------------------------- Total 17,955 $1,865 21,667 $1,769 16,695 $1,591 ---------------------------------------------------------- Factors Influencing Future Performance Performance of the Company in the near future will depend primarily on the ratemaking and regulatory process, electric- and natural gas-industry restructuring, and the changing energy marketplace. These factors are summarized below. KN Energy Acquisition. On February 22, 1999, Sempra Energy announced a definitive agreement to acquire KN Energy, Inc., subject to approval by the shareholders of both companies and by various regulatory agencies. See Note 14 of the notes to Consolidated Financial Statements for additional information. Electric Industry Restructuring. As discussed above, in September 1996, California enacted a law restructuring California's electric- utility industry (AB 1890). Consumers now have the opportunity to choose to continue to purchase their electricity from the local utility under regulated tariffs, to enter into contracts with other energy-service providers (direct access) or to buy their power from the PX that serves as a wholesale power pool allowing all energy producers to participate competitively. The local utility continues to provide distribution service regardless of which source the consumer chooses. See Note 12 of the notes to Consolidated Financial Statements for additional information. Transition Costs. AB 1890 allows 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 the CTC. Utilities are allowed a reasonable opportunity to recover their stranded costs through December 31, 2001. Stranded costs include sunk costs, as well as ongoing costs the CPUC finds reasonable and necessary to maintain generation facilities through December 31, 2001. These costs also include other items SDG&E has accrued under cost-of-service regulation. Through December 31, 1998, SDG&E has recovered transition costs of $500 million for nuclear generation and $200 million for non-nuclear generation. Excluding the costs of purchased power and other costs whose recovery is not limited to the pre-2002 period, the balance of the Company's stranded assets at December 31, 1998 is $600 million, consisting of $400 million for the power plants and $200 million of related deferred taxes and undercollections. During the 1998 - 2001 period, recovery of transition costs is limited by a rate cap. See Note 12 of the notes to Consolidated Financial Statements for additional information. Electric Generation Assets. In November 1997, the Company adopted a plan to auction its power plants and other electric-generating assets so that it could continue to concentrate its business on the transmission and distribution of electricity and natural gas as California opens its electric-utility industry to competition. The plan included the divestiture of the Company'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, 1998, of $400 million ($100 million for fossil and $300 million for SONGS). In March 1998, the CPUC's decision approving the PE/Enova Business Combination required, among other things, the divestiture by the Company of its fossil-fueled generation units. On December 11, 1998, the Company entered into agreements for the sale of the Company's South Bay and Encina Power Plants and 17 combustion- turbine generators. The sales are subject to regulatory approval and are expected to close during the first half of 1999. See Note 12 of the notes to Consolidated Financial Statements for additional information. Electric Rates. AB 1890 provides for a 10-percent reduction of residential and small commercial customers effective January 1998, and provided for the issuance of rate-reduction bonds by an agency of the State of California to enable the investor-owned utilities (IOUs) to achieve 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 the Company'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 the Company 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, the Company sold to SDG&E Funding LLC all of its rights to the revenue streams. Consequently, the revenue streams are not the property of the Company and are not available to creditors of the Company. AB 1890 also included a rate freeze for all customers. Until the earlier of March 31, 2002, or when transition cost recovery is complete, the Company's average system rate will be frozen at 9.64 cents per kilowatt-hour (kwh), except for the impacts of fuel-cost changes and the 10-percent rate reduction described above. Beginning in 1998, system-average rates were fixed at 9.43 cents per kwh, which includes the maximum permitted increase related to fuel-cost increases and the mandatory rate reduction. The Company's ability to recover its transition costs is dependent on its total revenues under the rate freeze exceeding traditional cost-of- service revenues during the transition period by at least the amount of the CTC less the net proceeds from the sale of electric- generating assets. During the transition period, SDG&E will not earn awards from special programs, such as Demand-Side Management, unless total revenues are also adequate to cover the awards. Fuel- price volatility is one of the more significant uncertainties in the ability of SDG&E to recover its transition costs and program awards. In early 1999, the Company filed with the CPUC for an interim mechanism to deal with electric rates after the rate freeze ends, noting the possibility that the SDG&E rate freeze could end in 1999. Performance-Based Regulation. As discussed above under PBR, regulators allow future income potential to be tied to achieving or exceeding specific performance and productivity measures, as well as cost reductions, rather than by relying solely on expanding utility rate base. See additional discussion of PBR in Note 12 of the notes to Consolidated Financial Statements. Regulatory Accounting Standards. The Company is accounting for the economic effects of regulation on its utility operations, except for electric generation, 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 the asset from customers. Regulatory liabilities represent future reductions in revenues for amounts due to customers. See Notes 2 and 12 of the notes to Consolidated Financial Statements for additional information. Affiliate Transactions. On December 16, 1997, the CPUC adopted rules establishing uniform standards of conduct governing the manner in which California IOUs conduct business with their affiliates. The objective of these rules, effective January 1, 1998, is to ensure that the Company's energy affiliates do not gain an unfair advantage over other competitors in the marketplace and that utility customers do not subsidize affiliate activities. The CPUC excluded utility-to-utility transactions between the Company and SoCalGas from the affiliate-transaction rules in its March 1998 decision approving the PE/Enova Business Combination. As a result, the affiliate-transaction rules will not substantially impact the Company's ability to achieve anticipated synergy savings. See Notes 1 and 12 of the notes to Consolidated Financial Statements for additional information. Allowed Rate of Return. For 1998, SDG&E was authorized to earn a rate of return on rate base of 9.35 percent and a rate of return on common equity of 11.6 percent, unchanged from 1997. See additional discussion in Note 12 of the notes to Consolidated Financial statements. Management Control of Expenses and Investment. In the past, management has been able to control operating expenses and capital investment within the amounts authorized to be collected in rates. It is the intent of management to control operating expenses and capital investments within the amounts authorized to be collected in rates in the PBR decision. The Company intends to make the efficiency improvements, changes in operations and cost reductions necessary to achieve this objective and earn its authorized rate of return. However, in view of the earnings-sharing mechanism and other elements of the PBR, it is more difficult to achieve returns at least at or in excess of authorized returns at levels experienced in past years. See additional discussion of PBR in Note 12 of the notes to Consolidated Financial Statements. Environmental Matters The Company's operations are conducted in accordance with applicable federal, state and local environmental laws and regulations governing such things as hazardous wastes, air and water quality, and the protection of wildlife. These costs of compliance are normally recovered in customer rates. Whereas it is anticipated that the environmental costs associated with natural gas operations and with electric transmission and generation operations will continue to be recoverable in rates, the restructuring of the California electric- utility industry, described above under "Electric Industry Restructuring," will change the way utility rates are set and costs associated with electric generation are recovered. 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 future compliance with environmental regulations may not be fully recoverable. Capital expenditures to comply with environmental laws and regulations were $1 million in 1998, $4 million in 1997 and $6 million in 1996, and are not expected to be significant during the next five years. These projected expenditures primarily consist of the estimated cost of reducing air emissions by retrofitting power plants. This estimate anticipates that SDG&E completes the planned sale of its fossil-fueled power plants during the first half of 1999. Additional information on the Company's divestiture of its electric generating assets is discussed above under "Electric Generation Assets" and in Note 12 of the notes to Consolidated Financial Statements. Hazardous Substances. In 1994, the CPUC approved the Hazardous Waste Collaborative, a mechanism which allows the Company and other utilities to recover, through rates, costs associated with the cleanup of sites contaminated with hazardous waste. In general, utilities are allowed to recover 90 percent of their cleanup costs and any related costs of litigation through rates. In early 1998, the CPUC modified this mechanism to exclude these costs related to electric-generation activities. These costs are now eligible for inclusion in the CTC recovery process described above. During the early 1900s, the Company and its predecessors manufactured gas from coal or oil, the sites of which have often become contaminated with the hazardous residual by-products of the process. The Company has identified three former manufactured gas plant sites. One of these sites has been remediated and a site- closure letter has been received from the San Diego County Department of Environmental Health. An environmental site assessment has been conducted and the estimated cost to remediate the other two sites is $6 million. Ninety percent of the Company's costs to clean up the gas plants and to meet their PRP obligations, a total estimated to be $15 million, is recoverable through the Hazardous Waste Collaborative mechanism. As a part of its sale of the South Bay and Encina power plants and 17 combustion turbines (described above), the Company retained limited remediation obligations for contamination existing on these sites upon the closing of the sales. The Company's costs to perform its remediation obligations as a part of such sales is estimated to be $10 million. These costs are eligible for inclusion in the CTC recovery process. Air and Water Quality. California's air quality standards are more restrictive than federal standards. However, due to the sale of the electric-generating power plants, the Company's primary air-quality issue, compliance with these standards will be less significant in the future. In connection with the issuance of operating permits, the Company and the other owners of SONGS reached agreement with the California Coastal Commission to mitigate the environmental damage to the marine environment attributed to the cooling-water discharge from SONGS Units 2 and 3. This mitigation program includes an enhanced fish-protection system, a 150-acre artificial reef and restoration of 150 acres of coastal wetlands. In addition, the owners must deposit $3.6 million with the state for the enhancement of marine fish hatchery programs and pay for monitoring and oversight of the mitigation projects. The Company'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 costs is expected to accommodate most of these added mitigation costs. The environmental laws and regulations regarding natural gas affect the operations of customers as well as the Company's regulated natural gas operations. Increasingly complex administrative and reporting requirements of environmental agencies applicable to commercial and industrial customers utilizing natural gas are not generally required of those using electricity. However, anticipated advancements in natural gas technologies are expected to enable natural gas equipment to remain competitive with alternate energy sources. The transmission and distribution of natural gas require the operation of compressor stations, which are subject to increasingly stringent air-quality standards. Costs to comply with these standards are recovered in rates. Other Income, Interest Expense and Income Taxes Other Income Other income, which primarily consists of interest income from short-term investments and regulatory accounts receivable balances, increased in 1998 to $21 million from $7 million in 1997. The increase was primarily due to interest earned on temporary investment balances, which were higher in 1998 than in 1997 due to cash received from the issuance of the rate-reduction bonds in December 1997. Other income increased slightly in 1997 to $7 million from $4 million in 1996. Interest Expense Interest expense for 1998 increased to $116 million from $86 million in 1997 primarily due to the issuance of rate-reduction bonds in December 1997. Interest expense for 1997 decreased to $86 million from $91 million in 1996 as a result of lower long-term debt balances throughout most of 1997. Income Taxes Income tax expense was $142 million, $219 million and $198 million in 1998, 1997 and 1996, respectively. These represent effective tax rates of 43 percent, 48 percent and 47 percent for the same periods. The decrease in the effective tax rate in 1998 is primarily due to tax issues related to the recovery of CTC. Derivative Financial Instruments The Company's policy is to use derivative financial instruments to manage exposure to fluctuations in interest rates, foreign currency exchange rates and energy prices. Transactions involving these financial instruments are with reputable firms and major exchanges. The use of these instruments may expose the Company to market and credit risks. At times, credit risk may be concentrated with certain counterparties, although counterparty nonperformance is not anticipated. The Company periodically enters into interest-rate swap and cap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. These swap and cap agreements generally remain off the balance sheet as they involve the exchange of fixed-rate 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. The Company 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, 1998 and 1997, the notional amount of swap transactions totaled $45 million. See Note 9 of the notes to Consolidated Financial Statements for further information regarding these swap transactions. The Company uses energy derivatives to manage natural gas price risk associated with servicing its load requirements. These instruments include forward contracts, futures, swaps, options and other contracts, with maturities ranging from 30 days to 12 months. In the case of price-risk management activities, the use of derivative financial instruments by the Company is subject to certain limitations imposed by established Company policy and regulatory requirements. See Note 9 of the notes to Consolidated Financial Statements and the "Market Risk Management Activities" section below for further information regarding the use of energy derivatives by the Company. Market Risk Management Activities Market risk is the risk of erosion of the Company's cash flows, net income and asset values due to adverse changes in interest and foreign-currency rates, and in prices for energy. The Company has adopted corporate-wide policies governing its market-risk management activities. An Energy Risk Management Oversight Committee, consisting of senior corporate officers, oversees Company-wide energy-price risk-management activities to ensure compliance with the Company's stated energy risk-management policies. Along with other tools, the Company uses Value at Risk (VaR) to measure its exposure to market risk. VaR is an estimate of the potential loss on a position or portfolio of positions over a specified holding period, based on normal market conditions and within a given statistical confidence level. The Company has adopted the variance/covariance methodology in its calculation of VaR, and uses a 95 percent confidence level. Holding periods are specific to the types of positions being measured, and are determined based on the size of the position or portfolios, market liquidity, tenor and other factors. Historical volatilities and correlations between instruments and positions are used in the calculation. The following is a discussion of the Company's primary market- risk exposures as of December 31, 1998, including a discussion of how these exposures are managed. Interest Rate Risk The Company is exposed to fluctuations in interest rates primarily as a result of its fixed-rate long-term debt. The Company has historically funded its operations through long-term bond issues with fixed interest rates. With the restructuring of the regulatory process, greater flexibility has been permitted within the debt- management process. As a result, recent debt offerings have been selected with short-term maturities to take advantage of yield curves or used a combination of fixed- and floating-rate debt. Interest rate swaps, subject to regulatory constraints, may be used to adjust interest-rate exposures when appropriate, based upon market conditions. The VaR on the Company's fixed rate long-term debt is estimated at approximately $129 million as of December 31, 1998, assuming a one-year holding period. Energy Price Risk Market risk related to physical commodities is based upon potential fluctuations in natural gas, petroleum and electricity commodity exchange prices and basis. The Company's market risk is impacted by changes in volatility and liquidity in the markets in which these instruments are traded. The Company is exposed, in varying degrees, to price risk in the natural gas, petroleum and electricity markets. The Company's policy is to manage this risk within a framework that considers the unique markets, operating and regulatory environment. Market Risk The Company is exposed to market risk in its natural gas purchase, sale and storage activities whenever natural gas prices fall outside the PBR tolerance band. SDG&E manages this risk within the parameters of the Company's market-risk management framework. As of December 31, 1998 the total VaR of the Company's natural gas positions was not material. SDG&E is exposed to market risk on its electricity purchases and sales under the electricity rate cap. See Note 12 of the notes to Consolidated Financial Statements and the discussion under the "Factors Influencing Future Performance" section for further information regarding the electricity rate cap. 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. The Company avoids concentration of counterparties and maintains 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 that allow for the netting of positive and negative exposures associated with a single counterparty. The Company monitors credit risk through a credit-approval process and the assignment and monitoring of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. Year 2000 Issues Most companies are affected by the inability of many automated systems and applications to process the year 2000 and beyond. The Year 2000 issues are the result of computer programs and other automated processes using two digits to identify a year, rather than four digits. Any of the Company's computer programs that include date-sensitive software may recognize a date using "00" as representing the year 1900, instead of the year 2000, or "01" as 1901, etc., which could lead to system malfunctions. The Year 2000 issue impacts both Information Technology (IT) systems and also non-IT systems, including systems incorporating "embedded processors." To address this problem, in 1996, both Pacific Enterprises and Enova Corporation established company-wide Year 2000 programs. These programs have now been consolidated into the Sempra Energy's overall Year 2000 readiness effort. Sempra Energy has established a central Year 2000 Program Office which reports to the its Chief Information Technology Officer and reports periodically to the audit committee of the Board of Directors. The Company's State of Readiness Sempra Energy is identifying all IT and non-IT systems that might not be Year 2000 ready and categorizing them in the following areas: IT applications, computer hardware and software infrastructure, telecommunications, embedded systems and third parties. Sempra Energy is currently evaluating its exposure in all of these areas. These systems and applications are being tracked and measured through four key phases: inventory, assessment, remediation/testing and Year 2000 readiness. Those applications and systems, which, if not appropriately remediated, may have a significant impact on energy delivery, revenue collection or the safety of personnel, customers or facilities, are being assessed and modified/replaced first. The testing effort includes functional testing of Year 2000 dates and validating that changes have not altered existing functionality. Sempra Energy uses an independent, internal-review process to verify that the appropriate testing has occurred. Inventory and assessment for all company systems were completed by January 1999 and ongoing inventory and assessment will be performed, as necessary, on any new applications. The project is on schedule and the Company estimates that by June 30, 1999, all critical systems will be suitable for continued use into the year 2000 with no significant operational problems. Sempra Energy's current schedule for Year 2000 testing, readiness and development of contingency plans is subject to change depending upon the remediation and testing phases of its compliance effort and upon developments that may arise as the Company continues to assess its computer-based systems and operations. In addition, this schedule is dependent upon the efforts of third parties, such as suppliers (including energy producers) and customers. Accordingly, delays by third parties may cause Sempra Energy's schedule to change. Costs to Address Sempra Energy's Year 2000 Issues Sempra Energy's budget for the Year 2000 program is $48 million, of which $38 million has been spent. As Sempra Energy continues to assess its systems and as the remediation and testing efforts progress, cost estimates may change. Sempra Energy's Year 2000 readiness effort is being funded entirely by operating cash flows. The Risks of Sempra Energy's Year 2000 Issues Based upon its current assessment and testing of the Year 2000 issue, Sempra Energy believes the reasonably likely worst case Year 2000 scenarios to have the following impacts upon its operations. With respect to Sempra Energy's ability to provide energy to its domestic utility customers, it believes that the reasonably likely worst case scenario is for small, localized interruptions of natural gas or electrical service which are restored in a time- frame that is within normal service levels. With respect to services that are essential to Sempra Energy's operations, such as customer service, business operations, supplies and emergency response capabilities, the scenario is for minor disruptions of essential services with rapid recovery and all essential information and processes ultimately recovered. To assist in preparing for and mitigating these possible scenarios, Sempra Energy is a member of several industry-wide efforts established to deal with Year 2000 problems affecting embedded systems and equipment used by the nation's natural gas and electric power companies. Under these efforts, participating utilities are working together to assess specific vendors' system problems and to test plans. These assessments will be shared by the industry as a whole to facilitate Year 2000 problem solving. A portion of this risk is due to the various Year 2000 schedules of critical third-party suppliers and customers. Sempra Energy is in the process of contacting its critical suppliers and customers to survey their Year 2000 remediation programs. While risks related to the lack of Year 2000 readiness by third parties could materially and adversely affect the Company's business, results of operations and financial condition, the Company expects its Year 2000 readiness efforts to reduce significantly the Company's level of uncertainty about the impact of third party Year 2000 issues on both its IT systems and non-IT systems. Company's Contingency Plans Sempra Energy's contingency plans for Year-2000-related interruptions are being incorporated in its existing overall emergency preparedness plans. To the extent appropriate, such plans will include emergency backup and recovery procedures, remediation of existing systems parallel with installation of new systems, replacing electronic applications with manual processes, identification of alternate suppliers and increasing inventory levels. Sempra Energy expects these contingency plans to be completed by June 30, 1999. Due to the speculative and uncertain nature of contingency planning, there can be no assurances that such plans actually will be sufficient to reduce the risk of material impacts on Sempra Energy's operations due to Year 2000 issues. New Accounting Standards In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivative Instruments and Hedging Activities." This statement, which is effective January 1, 2000, requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value and recognize changes in the fair value of derivatives in earnings in the period of change unless the derivative qualifies as an effective hedge that offsets certain exposures. The effect of this standard on the Company's Consolidated Financial Statements has not yet been determined. Information Regarding Forward-Looking Statements This report 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. The words "estimates," "believes," "expects," "anticipates," "plans" and "intends," variations of such words, and similar expressions are intended to identify forward-looking statements that involve risks and uncertainties which could cause actual results to differ materially from those anticipated. These statements are necessarily based upon various assumptions involving judgments with respect to the future including, among others, local, regional, national, and international economic, competitive, political and regulatory conditions and developments, technological developments, capital market conditions, inflation rates, interest rates, energy markets, weather conditions, business and regulatory or legal decisions, the pace of deregulation of retail natural gas and electricity industries, the timing and success of business development efforts, and other uncertainties, all of which are difficult to predict and many of which are beyond the control of the Company. Accordingly, while the Company believes that the assumptions are reasonable, there can be no assurance that they will approximate actual experience, or that the expectations will be realized. Readers are urged to carefully review and consider the risks, uncertainties and other factors which affect the Company's business described in this annual report and other reports filed by the Company from time to time with the Securities and Exchange Commission. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required by Item 7A is set forth under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk Management Activities." ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders 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, 1998 and 1997, and the related statements of consolidated income, changes in shareholders' equity, and cash flows for each of the three years in the period ended December 31, 1998. 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 as of December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998 in conformity with generally accepted accounting principles. /s/ DELOITTE & TOUCHE LLP San Diego, California January 27, 1999, except for Note 14 as to which the date is February 22, 1999 SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY STATEMENTS OF CONSOLIDATED INCOME Dollars in millions For the years ended December 31 1998 1997 1996 ------- ------- ------- Operating Revenues Electric $1,865 $1,769 $1,591 PX / ISO power 500 -- -- Gas 384 398 348 ------- ------- ------- Total 2,749 2,167 1,939 ------- ------- ------- Expenses Electric fuel 177 164 134 Purchased power 292 441 311 PX / ISO power 468 -- -- Gas purchased for resale 166 183 152 Maintenance 106 87 58 Depreciation and decommissioning 603 324 314 Property and other taxes 42 43 45 General and administrative 290 213 248 Other 186 178 166 Income taxes 133 217 202 ------- ------- ------- Total 2,463 1,850 1,630 ------- ------- ------- Operating Income 286 317 309 ------- ------- ------- Other Income and (Deductions) Allowance for equity funds used during construction 5 5 5 Taxes on nonoperating income (9) (2) 4 Other - net 25 4 (5) ------- ------- ------- Total 21 7 4 ------- ------- ------- Income Before Interest Charges 307 324 313 ------- ------- ------- Interest Charges Long-term debt 96 69 76 Short-term debt and other 14 14 13 Amortization of debt discount and expense, less premium 8 5 5 Allowance for borrowed funds used during construction (2) (2) (3) ------- ------- ------- Total 116 86 91 ------- ------- ------- Net Income 191 238 222 Preferred Dividend Requirements 6 6 6 ------- ------- ------- Earnings Applicable to Common Shares $ 185 $ 232 $ 216 ======= ======= ======= See notes to Consolidated Financial Statements. SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY CONSOLIDATED BALANCE SHEETS Dollars in millions Balance at December 31 1998 1997 ------- ------- ASSETS Utility plant - at original cost $4,903 $4,750 Accumulated depreciation and decommissioning (2,603) (2,391) ------ ------ Utility plant - net 2,300 2,359 ------ ------ Nuclear decommissioning trust 494 399 ------ ------ Current assets Cash and temporary investments 284 536 Accounts receivable 199 229 Due from affiliates 110 126 Inventories 77 65 Regulatory balancing accounts undercollected - net 9 -- Other 17 52 ------ ------ Total current assets 696 1,008 ------ ------ Deferred taxes recoverable in rates 194 185 Regulatory assets 435 608 Deferred charges and other assets 138 95 ------ ------ Total $4,257 $4,654 ====== ====== CAPITALIZATION AND LIABILITIES Capitalization Common equity $1,124 $1,387 Preferred stock not subject to mandatory redemption 78 78 Preferred stock subject to mandatory redemption 25 25 Long-term debt 1,548 1,788 ------ ------ Total capitalization 2,775 3,278 ------- ------ Current liabilities Current portion of long-term debt 72 73 Accounts payable 165 161 Dividends payable 102 46 Interest accrued 9 11 Regulatory balancing accounts overcollected - net -- 58 Other 185 114 ------ ------ Total current liabilities 533 463 ------ ------ Customer advances for construction 41 38 Deferred income taxes - net 397 440 Deferred investment tax credits 89 94 Deferred credits and other liabilities 422 341 Contingencies and commitments (Note 11) -- -- ------ ------ Total $4,257 $4,654 ====== ====== See notes to Consolidated Financial Statements. SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY STATEMENTS OF CONSOLIDATED CASH FLOWS Dollars in millions For the years ended December 31 1998 1997 1996 -------- -------- -------- Cash Flows from Operating Activities Net income $ 191 $ 238 $ 222 Adjustments to reconcile net income to net cash provided by operating activities Depreciation and decommissioning 603 324 314 Allowance for equity funds used during construction (5) (5) (5) Deferred income taxes and investment tax credits (132) 10 (16) Application of balancing accounts to stranded costs (86) -- -- Other - net (64) 21 28 Changes in working capital components Accounts receivable 30 (41) 18 Inventories (12) (2) 5 Other current assets 51 (4) (14) Interest and taxes accrued 39 (40) (25) Accounts payable and other current liabilities (66) (143) 50 Regulatory balancing accounts (14) 23 (37) Cash used by discontinued operations -- -- (11) ------- ------- ------- Net cash provided by operating activities 535 381 529 ------- ------- ------- Cash Flows from Investing Activities Utility construction expenditures (227) (197) (209) Contributions to decommissioning funds (22) (22) (22) Other - net (28) 5 (3) ------- ------- ------- Net cash used by investing activities (277) (214) (234) ------- ------- ------- Cash Flows from Financing Activities Dividends paid (269) (256) (189) Issuances of long-term debt -- 677 227 Repayment of long-term debt (241) (133) (258) Redemption of preferred stock -- -- (15) ------- ------- ------- Net cash provided (used) by financing activities (510) 288 (235) ------- ------- ------- Net increase (decrease) (252) 455 60 Cash and temporary investments, January 1 536 81 21 ------- ------- ------- Cash and temporary investments, December 31 $ 284 $ 536 $ 81 ======= ======= ======= See notes to Consolidated Financial Statements. SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY STATEMENTS OF CONSOLIDATED CASH FLOWS (continued) Dollars in millions For the years ended December 31 1998 1997 1996 -------- -------- -------- Supplemental Disclosure of Cash Flow Information Cash paid during the year for: Income tax payments, net of refunds $ 207 $ 217 $ 245 ======= ======= ======= Interest payments, net of amounts capitalized $ 118 $ 89 $ 94 ======= ======= ======= Supplemental Schedule of Non-Cash Transactions Net assets of affiliates transferred to parent $ -- $ -- $ 150 ======= ======= ======= Dividend to parent of intercompany receivable $ 100 $ -- $ -- ======= ======= ======= Property dividend to parent $ 29 $ -- $ -- ======= ======= ======= See notes to Consolidated Financial Statements. SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY For the years ended December 31, 1998, 1997, 1996 (Dollars in millions) Preferred Stock ------------------------ Not Subject Subject to to Mandatory Mandatory Common Retained Redemption Redemption Stock Earnings - ------------------------------------------------------------------------------ Balance at December 31, 1995 $ 93 $ 25 $ 857 $ 662 Net income 222 Transfer to Enova Corporation (150) Preferred stock retired (15) Preferred stock dividends declared (6) Common stock dividends declared (182) - ------------------------------------------------------------------------------ Balance at December 31, 1996 78 25 857 546 Net income 238 Special dividend to Enova Corporation (70) Preferred stock dividends declared (6) Common stock dividends declared (178) - ------------------------------------------------------------------------------ Balance at December 31, 1997 78 25 857 530 Net income 191 Special dividends to Sempra Energy (129) Preferred dividends declared (6) Common stock dividends declared (319) - ------------------------------------------------------------------------------ Balance at December 31, 1998 $ 78 $ 25 $ 857 $ 267 ============================================================================== See notes to Consolidated Financial Statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1: BUSINESS COMBINATION On June 26, 1998, Enova Corporation (Enova), parent company of San Diego Gas & Electric Company (SDG&E), and Pacific Enterprises (PE) combined into a new company named Sempra Energy. As a result of the combination, (i) each outstanding share of common stock of Enova was converted into one share of common stock of Sempra Energy, (ii) each outstanding share of common stock of PE was converted into 1.5038 shares of common stock of Sempra Energy and (iii) the preferred stock and preference stock of SDG&E; PE; and PE's principal subsidiary, Southern California Gas Company (SoCalGas), remained outstanding. The combination was approved by the shareholders of both companies on March 11, 1997 and was a tax-free transaction. The Consolidated Financial Statements of Sempra Energy and its subsidiaries give effect to the business combination using the pooling-of-interests method. As required by the March 1998 decision of the California Public Utilities Commission (CPUC) approving the business combination, SDG&E has entered into agreements to sell its fossil-fueled generation units. The sales are subject to regulatory approvals and are expected to close during the first half of 1999. Additional information concerning the sale of SDG&E's power plants is provided in Note 12. In addition, SoCalGas has sold its options to purchase the California portions of the Kern River and Mojave Pipeline natural gas transmission facilities. The Federal Energy Regulatory Commission's (FERC) approval of the combination includes conditions that the combined company will not unfairly use any potential market power regarding natural gas transportation to fossil-fueled generation plants. The FERC also specifically noted that the divestiture of SDG&E's fossil-fueled generation plants would eliminate any concerns about vertical market power arising from transactions between SDG&E and SoCalGas. NOTE 2: SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation The Consolidated Financial Statements include the accounts of SDG&E and its sole subsidiary, SDG&E Funding LLC. All material intercompany accounts and transactions have been eliminated. Property, Plant and Equipment This primarily represents the buildings, equipment and other facilities used by the Company to provide natural gas and electric utility 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 electric- industry restructuring and its effect on utility plant is included in Note 12. Utility plant balances by major functional categories at December 31, 1998, are: electric distribution $2.4 billion, natural gas operations $0.9 billion, electric transmission $0.7 billion, electric generation $0.6 billion and other electric $0.3 billion. The corresponding amounts at December 31, 1997, were essentially the same. Accumulated depreciation and decommissioning of natural gas and electric utility plant in service at December 31, 1998, are $0.4 billion and $2.2 billion, respectively, and at December 31, 1997, were $0.4 billion and $2.0 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 CPUC. The provisions for depreciation as a percentage of average depreciable utility plant (by major functional categories) in 1998, 1997, and 1996, respectively are: natural gas operations 4.01, 4.03, 4.07, electric generation 6.49, 5.60, 5.60, electric distribution 4.49, 4.39, 4.38, electric transmission 3.31, 3.28, 3.25, and other electric 6.29, 6.02, 5.95. The increase for electric generation in 1998 reflects the accelerated recovery of generation facilities. See Note 12 for additional discussion of generation facilities and industry restructuring. 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. Inventories Materials and supplies are $48 million and $43 million at December 31, 1998 and 1997, respectively. Fuel oil inventory is $29 million and $22 million at December 31, 1998 and 1997, respectively. Materials and supplies are generally valued at the lower of average cost or market; fuel oil is valued by the last-in first-out method. Effects of Regulation SDG&E accounting policies conform with generally accepted accounting principles for regulated enterprises and reflect the policies of the CPUC and the FERC. 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 rates for amounts due to customers. To the extent that portions of the utility operations were no longer subject to SFAS No. 71, or recovery was no longer probable as a result of changes in regulation or their 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 and for 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 12, California enacted a law restructuring the electric-utility industry. The law adopts the December 1995 CPUC policy decision, and allows California electric utilities the opportunity to recover existing utility plant and regulatory assets over a transition period that ends in 2001. In 1997, SDG&E ceased the application of SFAS No. 71 with respect to its electric- generation business. The application of SFAS No. 121 continues to be evaluated as industry restructuring progresses. Additional information concerning regulatory assets and liabilities is described below in "Revenues and Regulatory Balancing Accounts" and in Note 12. Revenues and Regulatory Balancing Accounts Revenues from utility customers consist of deliveries to customers and the changes in regulatory balancing accounts. Previously, 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 were eliminated by balancing accounts authorized by the CPUC. This is still the case for most natural gas operations. However, as a result of California's electric-restructuring law, overcollections recorded in SDG&E's Energy Cost Adjustment Clause and Electric Revenue Adjustment Mechanism balancing accounts were transferred to the Interim Transition Cost Balancing Account, which is being applied to transition cost recovery, and fluctuations in costs and consumption levels can affect earnings from electric operations. Additional information on electric-industry restructuring is included in Note 12. Regulatory Assets Regulatory assets include San Onofre Nuclear Generating Station (SONGS), post-retirement benefit costs, deferred income taxes recoverable in rates and other regulatory-related expenditures that the Company expects to recover in future rates. See Note 12 for additional information. Nuclear Decommissioning Liability Deferred credits and other liabilities at December 31, 1998, include $146 million ($117 million in 1997) of accumulated decommissioning costs associated with the Company's SONGS Unit 1, which was permanently shut down in 1992. Additional information on SONGS Unit 1 decommissioning costs is included in Note 5. The corresponding liability for Units 2 and 3 is included in accumulated depreciation and amortization. Comprehensive Income In 1998, the Company adopted SFAS No. 130, "Reporting Comprehensive Income." This statement requires reporting of comprehensive income and its components (revenues, expenses, gains and losses) in any complete presentation of general-purpose financial statements. Comprehensive income describes all changes, except those resulting from investments by owners and distributions to owners, in the equity of a business enterprise 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. Comprehensive income was equal to net income for the years ended December 31, 1998, 1997, and 1996. Use of Estimates in the Preparation of the Financial Statements The preparation of the consolidated 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 presentation. New Accounting Standard In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivative Instruments and Hedging Activities." This statement, which is effective January 1, 2000, requires that an entity recognize all derivatives as either assets or liabilities in the statement of financial position, measure those instruments at fair value and recognize changes in the fair value of derivatives in earnings in the period of change unless the derivative qualifies as an effective hedge that offsets certain exposures. The effect of this standard on the Company's Consolidated Financial Statements has not yet been determined. NOTE 3: SHORT-TERM BORROWINGS SDG&E has $30 million of bank lines available to support commercial paper and $265 million of bank lines available to support variable- rate, long-term debt. The credit agreements expire at varying dates from 1999 through 2000 and bear interest at various rates based on market rates and the Company's credit rating. SDG&E's bank lines of credit were unused at both December 31, 1998, and 1997. NOTE 4: LONG-TERM DEBT - ------------------------------------------------------------------- December 31, (Dollars in millions) 1998 1997 - ------------------------------------------------------------------- First Mortgage Bonds 7.625% June 15, 2002 $ 28 $ 80 6.800% June 1, 2015 14 14 5.900% June 1, 2018 71 71 5.900% September 1, 2018 93 93 6.100% September 1, 2018 40 40 6.400% September 1, 2018 43 43 6.100% September 1, 2019 35 35 9.625% April 15, 2020 10 54 Variable rates September 1, 2020 58 75 5.850% June 1, 2021 60 60 8.500% April 1, 2022 10 44 5.420% December 1, 2027 45 45 6.400% December 1, 2027 75 75 Variable rates December 1, 2027 130 130 ------------------------ 712 859 ------------------------ Unsecured Bonds 5.900% June 1, 2014 130 130 Variable % July 1, 2021 39 39 Variable % December 1, 2021 60 60 Variable % March 1, 2023 25 25 ------------------------ 254 254 ------------------------ Rate-reduction bonds 592 658 Capital leases 63 95 Other long-term debt -- 1 ------------------------ Total 1,621 1,867 Less: Long term debt due within one year 72 73 Unamortized debt discount less premium 1 6 ------------------------ Total $1,548 $1,788 - ------------------------------------------------------------------- First-Mortgage Bonds First-mortgage bonds are secured by a lien on substantially all of SDG&E's utility plant. SDG&E may issue additional first-mortgage bonds upon compliance with the provisions of their bond indentures, which provide for, among other things, the issuance of an additional $712 million of first-mortgage bonds at December 31, 1998. SDG&E retired $147 million of first-mortgage bonds prior to scheduled maturity. Certain first-mortgage bonds may be called at SDG&E's option. SDG&E has $188 million of variable-interest-rate provisions that are callable at various dates within one year. 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. See Note 12 for additional information. 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. Interest Rate Swaps 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, 1998, SDG&E had such an agreement, maturing in 2002, with underlying debt of $45 million. 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, 1998, are: - --------------------------------------------------------------------- (Dollars in millions) Southwest Project SONGS Powerlink - --------------------------------------------------------------------- Percentage ownership 20 89 Regulatory assets $ 312 - Utility plant in service - $ 217 Accumulated depreciation and amortization - $ 104 Construction work in progress $ 18 $ 1 - --------------------------------------------------------------------- The Company's share of operating expenses is included in the Statements of Consolidated Income. Each participant in the facilities must provide its own financing. The amounts specified above for SONGS include nuclear production, transmission and other facilities. $11 million of substation equipment included in these amounts is wholly owned by the Company. 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 Commission and other regulatory bodies. The Company's share of decommissioning costs for the SONGS units is estimated to be $425 million in today's dollars and is based on a cost study completed in 1998. Cost studies are performed and updated periodically by outside consultants. Although electric-industry restructuring legislation requires that stranded costs, which include SONGS' costs, be amortized in rates by 2001, the recovery of decommissioning costs is allowed until the time that 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 the Company's share of future decommissioning costs. Payments to the nuclear-decommissioning trusts are expected to continue until SONGS is decommissioned, which is not expected to occur before 2013. Unit 1, although permanently shut down in 1992, was scheduled to be decommissioned concurrently with Units 2 and 3. However, the Company and the other owners of SONGS have requested that the CPUC grant authority to begin decommissioning Unit 1 on January 1, 2000. The amounts collected in rates are invested in externally managed trust funds. The securities held by the trust are considered available for sale and are shown on the Consolidated Balance Sheets adjusted to market value. The fair values reflect unrealized gains of $149 million and $89 million at December 31, 1998, and 1997, respectively. 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 the Company's future balance sheets include a liability for the estimated decommissioning costs, and a related increase in the cost of the asset. Additional information regarding SONGS is included in Notes 11 and 12. NOTE 6: INCOME TAXES The reconciliation of the statutory federal income tax rate to the effective income tax rate is as follows: - ------------------------------------------------------------- 1998 1997 1996 - ------------------------------------------------------------- Statutory federal income tax rate 35.0% 35.0% 35.0% Depreciation 0.1 7.1 5.7 State income taxes - net of federal income tax benefit 5.6 5.7 6.1 Tax credits (1.7) (1.3) (2.1) Other - net 3.6 1.4 2.3 --------------------------- Effective income tax rate 42.6% 47.9% 47.0% - ------------------------------------------------------------- The components of deferred income taxes at December 31 are as follows: - ------------------------------------------------------------- (Dollars in millions) 1998 1997 - ------------------------------------------------------------- Deferred tax liabilities Differences in financial and tax bases of utility plant $ 440 $ 568 Regulatory balancing accounts 74 - Loss on reacquired debt 34 31 Other 71 33 --------------------------- Total deferred tax liabilities 619 632 --------------------------- Deferred tax assets Unamortized investment tax credits 63 65 Regulatory balancing accounts - 28 Unbilled revenue 22 22 Other 100 90 --------------------------- Total deferred tax assets 185 205 --------------------------- Net deferred income tax liability 434 427 Current portion - net asset (liability) (37) 13 --------------------------- Non-current portion - net liability $ 397 $ 440 - ------------------------------------------------------------- The components of income tax expense are as follows: - ------------------------------------------------------------- (Dollars in millions) 1998 1997 1996 - ------------------------------------------------------------- Current Federal $ 150 $ 164 $ 169 State 41 44 45 --------------------------- Total current taxes 191 208 214 --------------------------- Deferred Federal (30) 13 (9) State (16) 2 (1) --------------------------- Total deferred taxes (46) 15 (10) --------------------------- Deferred investment tax credits - net (3) (4) (6) --------------------------- Total income tax expense $ 142 $ 219 $ 198 - ------------------------------------------------------------- Federal and state income taxes are allocated between operating income and other income. NOTE 7: EMPLOYEE BENEFIT PLANS The information presented below describes the plans of the Company. In connection with the PE/Enova Business Combination described in Note 1, certain of these plans have been or will be replaced or modified, and numerous participants have been or will be transferred from the Company's plans to those of Sempra Energy. Pension and Other Postretirement Benefits The Company sponsors qualified and nonqualified pension plans and other postretirement benefit plans for its employees. The following tables provide a reconciliation of the changes in the plans' benefit obligations and fair value of assets over the two years, and a statement of the funded status as of each year end: - ------------------------------------------------------------------------------- Other Pension Benefits Postretirement Benefits ----------------------------------------------- (Dollars in millions) 1998 1997 1998 1997 - -------------------------------------------------------------------------------- Weighted-Average Assumptions as of December 31: Discount rate 6.75% 7.25% 6.75% 7.25% Expected return on plan assets 8.50% 8.50% 8.50% 4.50% Rate of compensation increase 5.00% 5.00% 5.00% 5.00% Cost trend of covered health-care charges - - 8.00%(1) 7.00%(2) Change in Benefit Obligation: Net benefit obligation at January 1 $ 605 $ 546 $ 43 $ 41 Service cost 19 18 1 1 Interest cost 43 40 3 3 Plan amendments (3) - - - Actuarial (gain) loss (17) 19 5 1 Transfer of liability (3) (112) - - - Special termination benefits 9 - - - Gross benefits paid (50) (18) (4) (3) ----------------------------------------------- Net benefit obligation at December 31 494 605 48 43 ----------------------------------------------- Change in Plan Assets: Fair value of plan assets at January 1 699 598 14 12 Actual return on plan assets 103 118 1 1 Employer contributions 1 1 6 4 Transfer of assets (3) (166) - - - Gross benefits paid (50) (18) (4) (3) ----------------------------------------------- Fair value of plan assets at December 31 587 699 17 14 ----------------------------------------------- Funded status at December 31 93 94 (31) (29) Unrecognized net actuarial (gain) loss (196) (200) 1 (2) Unrecognized prior service cost 23 29 - - ----------------------------------------------- Net liability at December 31 (4) $ (80) $ (77) $ (30) $ (31) - --------------------------------------------------------------------------------- (1) Decreasing to ultimate trend of 6.50% in 2004. (2) Decreasing to ultimate trend of 6.50% in 1998. (3) To reflect transfer of plan assets and liability to Sempra Energy plan for Company employees transferred to Sempra Energy. (4) Approximates amounts recognized in the Consolidated Balance Sheets at December 31. Prior year amounts include non-qualified plans to be consistent with the current year presentation. The following table provides the components of net periodic benefit cost for the plans: - --------------------------------------------------------------------------------- Other Pension Benefits Postretirement Benefits ----------------------------------------------- (Dollars in millions) 1998 1997 1996 1998 1997 1996 ----------------------------------------------- Service cost $ 19 $ 18 $ 19 $ 1 $ 1 $ 1 Interest cost 43 40 39 3 3 3 Expected return on assets (60) (50) (45) (1) - - Amortization of: Transition obligation - - - 2 2 2 Prior service cost 3 3 3 - - - Actuarial gain (11) (9) (5) - - - Special termination benefit 9 - - - - - Regulatory adjustment - - (15) - (1) (1) ----------------------------------------------- Total net periodic benefit cost $ 3 $ 2 $ (4) $ 5 $ 5 $ 5 - --------------------------------------------------------------------------------- Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A 1% change in assumed health care cost trend rates would have the following effects: - ------------------------------------------------------------------------ (Dollars in millions) 1% Increase 1% Decrease - ------------------------------------------------------------------------ Effect on total of service and interest cost components of net periodic postretirement health care benefit cost -- -- Effect on the health care component of the accumulated postretirement benefit obligation $ 2 $ (1) - ------------------------------------------------------------------------ The projected benefit obligation and accumulated benefit obligation of the pension plan were $15 million and $14 million, respectively, as of December 31, 1998, and $16 million and $10 million, as of December 31, 1997. Other postretirement benefits include medical benefits for retirees and their spouses and retiree life insurance. Savings Plans SDG&E offers a savings plan, administered by plan trustees, to all eligible employees. Eligibility to participate in the plan begins after one month of service. Employees may contribute, subject to plan provisions, from 1 percent to 15 percent of their regular earnings. The employees' contributions, at the direction of the employees, are primarily invested in Sempra Energy common stock or mutual funds. Employer contributions, after one year of service, are made in shares of Sempra Energy common stock. Employer contributions are equal to 50 percent of the first 6 percent of eligible base salary contributed by employees. During 1998, SDG&E's plan contribution was age-based for represented employees. Annual expense for the savings plans was $5 million in 1998, $3 million in 1997 and $2 million in 1996. NOTE 8: STOCK-BASED COMPENSATION Sempra Energy has stock-based compensation plans that align employee and shareholder objectives related to Sempra Energy's long-term growth. The long-term incentive stock compensation plan provides for aggregate awards of Sempra Energy non-qualified stock options, incentive stock options, restricted stock, stock appreciation rights, performance awards, stock payments or dividend equivalents to eligible employees of Sempra Energy and its subsidiaries. In 1995, Statement of Financial Accounting Standards (SFAS) No. 123, "Accounting for Stock-Based compensation," was issued. It encourages a fair-value-based method of accounting for stock-based compensation. As permitted by SFAS No. 123, Sempra Energy and its subsidiaries adopted the statement's disclosure-only requirements and continue to account for stock-based compensation in accordance with the provisions of accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." To the extent that subsidiary employees participate in the plans or that subsidiaries are allocated a portion of Sempra Energy's costs of the plans, the subsidiaries record an expense for the plans. SDG&E recorded expenses of $2 million in 1998, $1 million in 1997 and $1 million in 1996. NOTE 9: FINANCIAL INSTRUMENTS Fair Value The fair values of the Company's financial instruments are not materially different from the carrying amounts, except for long- term debt. The carrying amounts and fair values of long-term debt are $1.5 billion and $1.6 billion, respectively, at December 31, 1998, and $1.8 billion each at December 31, 1997. The fair values of the first-mortgage and other bonds are estimated based on quoted market prices for them or for similar issues. Included in long-term debt are the Company's rate-reduction bonds. The carrying amounts and fair values of the rate-reduction bonds are $592 million and $607 million, respectively, at December 31, 1998, and $658 million each at December 31, 1997. Off-Balance-Sheet Financial Instruments The Company's policy is to use derivative financial instruments to manage its exposure to fluctuations in interest rates, foreign- currency exchange rates and energy prices. Transactions involving these financial instruments expose the Company to market and credit risks which may at times be concentrated with certain counterparties, although counterparty nonperformance is not anticipated. Swap Agreements The Company periodically enters into interest-rate-swap and cap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. These 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 consolidated income statement as part of interest expense. At December 31, 1998, and 1997, the Company 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 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 $3 million at December 31, 1998, and $2 million at December 31, 1997. Additional information on this topic is included in Note 4. Energy Derivatives The Company uses energy derivatives for price-risk management purposes within certain limitations imposed by Company policies and regulatory requirements. Energy derivatives are used to mitigate risk and better manage costs. These instruments include forward contracts, swaps, options and other contracts which have maturities ranging from 30 days to 12 months. For the years ended December 31, 1998, 1997, and 1996, gains and losses from these activities are not material to SDG&E's financial statements. NOTE 10: SHAREHOLDERS' EQUITY - -------------------------------------------------------------- December 31, (Dollars in millions) 1998 1997 - -------------------------------------------------------------- COMMON EQUITY Common stock, without par value, authorized 255,000,000 shares $ 857 $ 857 Retained earnings 267 530 ---------------------- Total common equity $ 1,124 $ 1,387 - -------------------------------------------------------------- All shares of SDG&E common stock are wholly owned by Enova Corporation. Dividend Restrictions The CPUC regulates SDG&E's capital structure, limiting the dividends it may pay. At December 31, 1998, $183 million of retained earnings was available for future dividends. - --------------------------------------------------------------- Call December 31, (Dollars in millions except call price) Price 1998 1997 - --------------------------------------------------------------- PREFERRED STOCK Not subject to mandatory redemption $20 par value, authorized 1,375,000 shares: 5% Series, 375,000 shares outstanding $ 24.00 $ 8 $ 8 4.50% Series, 300,000 shares outstanding $ 21.20 6 6 4.40% Series, 325,000 shares outstanding $ 21.00 6 6 4.60% Series, 373,770 shares outstanding $ 20.25 7 7 Without par value: $1.70 Series, 1,400,000 shares outstanding $ 25.85 35 35 $1.82 Series, 640,000 shares outstanding $ 26.00 16 16 -------------- Total not subject to mandatory redemption $78 $78 -------------- Subject to mandatory redemption Without par value $1.7625 Series, 1,000,000 shares outstanding $ 25.00 $25 $25 - --------------------------------------------------------------- All series of SDG&E's preferred stock have cumulative preferences as to dividends. The $20 par value preferred stock has two votes per share on matters being voted upon by shareholders of SDG&E and a liquidation value at par, whereas the no par value preferred stock is nonvoting and has a liquidation value of $25 per share. SDG&E is authorized to issue 10,000,000 shares of no par value stock (both subject to and not subject to mandatory redemption). All series are currently callable except for the $1.70 and $1.7625 series (callable in 2003). The $1.7625 series has a sinking fund requirement to redeem 50,000 shares per year from 2003 to 2007; the remaining 750,000 shares must be redeemed in 2008. NOTE 11: CONTINGENCIES AND COMMITMENTS Natural Gas Contracts SDG&E buys natural gas primarily from various spot-market suppliers. It also has long-term capacity contracts with interstate pipelines which expire on various dates between 2007 and 2023. 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 three of the suppliers. One of the three is delivering natural gas under the terms of the settlement agreement; the other two have ceased deliveries. The fourth supplier has ceased deliveries pending legal resolution. If the supply of Canadian natural gas to SDG&E is not resumed to a level approximating the related committed long-term pipeline capacity, SDG&E intends to continue using the capacity in other ways, including the transport of replacement natural gas and the release of a portion of this capacity to third parties. At December 31, 1998, the future minimum payments under natural gas contracts were: - --------------------------------------------------------------------- Storage and (Dollars in millions) Transportation Natural Gas - --------------------------------------------------------------------- 1999 $12 $18 2000 11 20 2001 9 22 2002 9 22 2003 9 23 Thereafter 128 - ------------------------ Total minimum payments $178 $105 - --------------------------------------------------------------------- Total payments under the short-term and long-term contracts were $103 million in 1998, $125 million in 1997, and $100 million in 1996. All of SDG&E's natural gas is delivered through SoCalGas pipelines under a short-term transportation agreement. In addition, SoCalGas provides SDG&E six billion cubic feet of natural gas storage capacity under an agreement expiring March 2000. These agreements are not included in the above table. Purchased Power Contracts SDG&E buys electric power under several long-term contracts. The contracts expire on various dates between 1999 and 2025. Under California's Electric Industry Restructuring law, which is described in Note 12, the California investor-owned electric utilities (IOUs) are obligated to bid their power supply, including owned generation and purchased-power contracts, into the California Power Exchange (PX). As a result, SDG&E's system requirements are met primarily through purchases from the PX. At December 31, 1998, the estimated future minimum payments under the long-term contracts were: - --------------------------------------------------------------------- (Dollars in millions) - --------------------------------------------------------------------- 1999 $ 249 2000 211 2001 174 2002 136 2003 135 Thereafter 2,001 -------- Total minimum payments $2,906 - --------------------------------------------------------------------- These payments for actual purchases 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 actual energy payments, under the contracts were $293 million in 1998, $421 million in 1997 and $296 million in 1996. Payments under purchased-power contracts decreased in 1998 as a result of the purchases from the PX, which commenced April 1, 1998. SDG&E has entered into agreements to sell its power plants and other electric-generating resources (excluding SONGS), and has announced a plan to auction its long-term purchased power contracts. Additional information on this topic is provided in Note 12. Leases SDG&E has capital and operating leases on real and personal property expiring at various dates from 1999 to 2030. SDG&E has nuclear fuel, office buildings, a generating facility and other properties that are financed by long-term capital leases. Utility plant includes $177 million at December 31, 1998, and $198 million at December 31, 1997, related to these leases. The associated accumulated amortization is $114 million and $102 million, respectively. SDG&E also has 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 (Dollars in millions) Leases Leases* - --------------------------------------------------------------------- 1999 $15 $27 2000 13 10 2001 12 10 2002 8 10 2003 7 10 Thereafter 34 5 ------------------------------------- Total future rental commitment $89 72 Imputed interest (6% to 9%) (10) ------- Net commitment $62 - --------------------------------------------------------------------- * These amounts are reduced by a total of $55 million upon SDG&E's divestiture of its fossil fuel generating facilities. Rent expense totaled $50 million in 1998, $43 million in 1997, and $46 million in 1996. Environmental Issues SDG&E believes that its 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 generally have been recovered in customer rates. 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. Recovery of 90 percent of cleanup costs and related third-party litigation costs and 70 percent of the related insurance-litigation expenses is permitted. Environmental liabilities that may arise are recorded when remedial efforts are probable and the costs can be estimated. At December 31, 1998, the utility's estimated remaining investigation and remediation liability related to hazardous waste sites was $15 million, of which 90 percent is authorized to be recovered through the Hazardous Waste Collaborative mechanism. SDG&E believes that any costs not ultimately recovered through rates, insurance or other means, upon giving effect to previously established liabilities, will not have a material adverse effect on the Company's consolidated results of operations or the financial position. SDG&E's capital expenditures to comply with environmental laws and regulations were $1 million in 1998, $4 million in 1997, and $6 million in 1996, and are not expected to be significant over the next five years. These expenditures primarily include the estimated cost of retrofitting SDG&E's power plants to reduce air emissions. These costs will be reduced significantly by SDG&E's sale of its non-nuclear generating facilities. SDG&E has been associated with various sites which may require remediation under federal, state or local environmental laws. SDG&E is unable to fully 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. SDG&E does not anticipate that such costs, net of the portion recoverable in rates, will be significant. As discussed in Note 12, restructuring of the California electric-utility industry will change the way utility rates are set and costs are recovered. SDG&E has asked that the collaborative account be modified, and that electric generation-related cleanup costs be eligible for transition-cost recovery. The final outcome of this decision is that SDG&E's costs of compliance with environmental regulations may 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 which have used DOE enrichment services are being assessed 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 through 1992. SDG&E's annual assessment is approximately $1 million. This assessment is recovered through SONGS revenue. Litigation SDG&E is 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 SDG&E's results of operations, financial condition or liquidity. Electric Distribution System Conversion Under a CPUC-mandated program and through franchise agreements with various cities, SDG&E is committed, in varying amounts, to converting overhead distribution facilities to underground. As of December 31, 1998, the aggregate unexpended amount of this commitment was approximately $104 million. Capital expenditures for underground conversions were $17 million in 1998 and 1997, and $15 million in 1996. Concentration of Credit Risk SDG&E maintains credit policies and systems to minimize overall credit risk. These policies include, when applicable, the use of an evaluation of potential counterparties' financial condition and an assignment of credit limits. These credit limits are established based on risk and return considerations under terms customarily available in the industry. SDG&E grants credit to its utility customers, substantially all of whom are located in SDG&E's service territory, which covers all of San Diego County and an adjacent portion of Orange County. NOTE 12: REGULATORY MATTERS Electric-Industry Restructuring In September 1996, California enacted a law restructuring its electric-utility industry (AB 1890). The legislation adopts the December 1995 CPUC policy decision restructuring the industry to stimulate competition and reduce rates. Beginning on March 31, 1998, customers were given the opportunity to choose to continue to purchase their electricity from the local utility under regulated tariffs, to enter into contracts with other energy-service providers (direct access) or to buy their power from the independent Power Exchange (PX) that serves as a wholesale power pool allowing all energy producers to participate competitively. The PX obtains its power from qualifying facilities, from nuclear units and, lastly, from the lowest-bidding suppliers. The California investor-owned electric utilities (IOUs) are obligated to sell their power supply, including owned- generation and purchased-power contracts, to the PX. The IOUs are also obligated to purchase from the PX the power that they distribute. An Independent System Operator (ISO) schedules power transactions and access to the transmission system. The local utility continues to provide distribution service regardless of which source the consumer chooses. An example of these changes in the electric-utility environment is the U.S. Navy, SDG&E's largest customer. The U.S. Navy's contract to purchase energy from SDG&E was not renewed when it expired on September 30, 1998. Instead, the U.S. Navy elected to obtain energy through direct access and SDG&E continues to provide the distribution service. Utilities are allowed a reasonable opportunity to recover their stranded costs via a competition transition charge (CTC) to customers through December 31, 2001. Stranded costs include sunk costs, as well as ongoing costs the CPUC finds reasonable and necessary to maintain generation facilities through December 31, 2001. These costs also include other items SDG&E has recorded under traditional cost-of-service regulation. Certain 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. To the extent that the opportunity to recover stranded costs is reduced by the costs to accommodate the implementation of direct access and the ISO/PX during the rate freeze (discussed below), those displaced stranded costs may be recovered after 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. Nuclear decommissioning costs are nonbypassable until fully recovered, but are not included as part of transition costs. Through December 31, 1998, SDG&E has recovered transition costs of $500 million for nuclear generation and $200 million for non-nuclear generation. Excluding the costs of purchased power and other costs whose recovery is not limited to the pre-2002 period, the balance of SDG&E's stranded assets at December 31, 1998, is $600 million, consisting of $400 million for the power plants and $200 million of related deferred taxes and undercollections. In November 1997, SDG&E 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, 1998, of $400 million ($100 million for fossil and $300 million for SONGS) and a combined generating capacity of 2,400 megawatts. The proceeds from the sales, net of the costs of the sales and certain environmental cleanup costs, will be applied directly to SDG&E's transition costs. The fossil-fuel assets' auction is being separated from the auction of SONGS and the purchased-power contracts. In October 1998, the CPUC issued an interim decision approving the commencement of the fossil fuel assets' auction. On December 11, 1998, contracts were executed for the sale of SDG&E's South Bay Power Plant, Encina Power Plant and 17 combustion-turbine generators. The South Bay Power Plant is being sold to the San Diego Unified Port District for $110 million. The Encina Power Plant and the combustion-turbine generators are being sold to a special-purpose entity owned equally by Dynegy Power Corp. and NRG Energy, Inc. for $356 million. The sales are subject to regulatory approval and are expected to close during the first half of 1999. During the 1998-2001 period, recovery of transition costs is limited by the rate freeze discussed below. Management believes that rates 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, not including the post-2001 purchased-power contracts payments that may be recovered after 2001. However, if 1998-2001 generation costs, principally fuel costs, are greater than anticipated, SDG&E may be unable to recover all of its approved transition costs. This would result in a charge against earnings at the time it ceases to be probable that SDG&E will be able to recover all of the transition costs. AB 1890 requires a 10-percent reduction of residential and small commercial customers' rates, beginning in January 1998, and provided for the issuance of rate-reduction bonds by an agency of the state of California to enable the IOUs to achieve 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 electric bills. In 1997, SDG&E formed a subsidiary, SDG&E Funding LLC, to facilitate the issuance of the bonds. In exchange for the bond proceeds, SDG&E sold to SDG&E Funding LLC all of its rights to certain revenue streams collected from such customers. Consequently, the transaction is structured to cause such revenue streams not to be the property of SDG&E nor to be available to satisfy any claims of SDG&E's creditors. AB 1890 includes a rate freeze for all electric 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 the June 10, 1996 levels of 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 were fixed at 9.43 cents per kwh, which includes the maximum permitted increase related to fuel-cost increases and the mandatory rate reduction. In early 1999, SDG&E filed with the CPUC for an interim mechanism to deal with electric rates after the rate freeze ends, noting the possibility that the SDG&E rate freeze could end in 1999. 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 California's investor-owned utilities (IOUs) may not meet the criteria of SFAS No. 71 with respect to their electric-generation regulatory assets. SDG&E has ceased the application of SFAS No. 71 to its generation business, in accordance with the conclusion of the Emerging Issues Task Force of the Financial Accounting Standards Board that the application of SFAS 71 should be discontinued when legislation is issued that determines that a portion of an entity's business will no longer be subject to traditional cost-of-service regulation. The discontinuance of SFAS No. 71 applied to the IOUs' 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 operations, subject to the rate freeze. In October 1997, the FERC approved key elements of the California IOUs' restructuring proposal. This included 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 the establishment of the California PX to operate as an independent wholesale power pool. The IOUs pay to the PX an upfront 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 expected to be recovered as a transition cost. The IOUs have guaranteed $300 million of commercial loans to the ISO and PX for their development and initial start-up. SDG&E's share of the guarantee is $30 million. Thus far, electric-industry deregulation has been confined to generation. Transmission and distribution have remained subject to traditional cost-of-service regulation. However, the CPUC is exploring the possibility of opening up electric distribution to competition. During 1999, the CPUC will be conducting a rulemaking, one objective of which may be to develop a coordinated proposal for the state legislature regarding how various distribution competition issues should be addressed. SDG&E and SoCalGas will actively participate in this effort. Natural Gas Industry Restructuring The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. On January 21, 1998, the CPUC released a staff report initiating a project to assess the current market and regulatory framework for California's natural gas industry. The general goals of the plan are to consider reforms to the current regulatory framework emphasizing market-oriented policies benefiting California natural gas consumers. On August 25, 1998, California adopted a law prohibiting the CPUC from enacting any natural gas industry restructuring decision for customers prior to January 1, 2000. During the implementation moratorium, the CPUC will hold hearings throughout the state and intends to give the California Legislature a report for its review detailing specific recommendations for changing the natural gas market within California. SDG&E will actively participate in this effort. Performance-Based Regulation (PBR) To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC has been directing utilities to use PBR. PBR has replaced the general rate case and certain other regulatory proceedings for SDG&E. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and productivity measures, as well as cost reductions, rather than relying solely on expanding utility rate base in a market where a utility already has a highly developed infrastructure. SDG&E participates in a PBR process for base rates for its electric and natural gas distribution business. In conjunction therewith, in December 1998, a Cost of Service settlement agreement among SDG&E, the CPUC's Office of Ratepayers' Advocates (ORA) and the Utility Consumers' Action Network (UCAN) was approved by the CPUC, resulting in an authorized revenue increase of $12 million (an electric-distribution increase of $18 million and a natural gas decrease of $6 million). The electric-distribution increase does not affect rates during the rate freeze and, therefore, reduces the amount available for transition cost recovery. Revised rates were effective January 1, 1999. In January 1999, an administrative law judge's proposed decision was issued on SDG&E's distribution PBR application. The proposed decision recommends a revenue-per-customer indexing mechanism rather than the rate-indexing mechanism proposed by SDG&E. Revenue or base margin per customer is indexed based on inflation less an estimated productivity factor. In addition, the proposed decision recommends much tighter earnings sharing bands. The performance indicators are as adopted in the settlement agreement, including employee safety, electric reliability, customer satisfaction, call-center responsiveness and electric- system maintenance. SDG&E would be authorized to earn or be penalized up to a maximum of $14.5 million annually as a result of its performance in those areas. Biennial Cost Allocation Proceeding (BCAP) In October 1998, SDG&E filed its 1999 BCAP application requesting that new rates become effective August 1, 1999 and remain in effect through December 31, 2002. The proposed end date aligns with the expiration of SDG&E's PBR. The application seeks overall decreases in natural gas revenues of $9 million. Cost of Capital Under PBR, annual Cost of Capital proceedings were replaced by an automatic adjustment mechanism if changes in certain indices exceed established tolerances. Electric-industry restructuring is changing the method of calculating SDG&E's annual cost of capital. In May 1998, the utility filed with the CPUC its unbundled Cost of Capital application for 1999 rates. The application seeks approval to establish new, separate rates of return for SDG&E's electric- distribution and natural gas businesses. The application proposes a 12.00 percent rate of return on common equity (ROE), which would produce an overall return on rate base (ROR) of 9.33 percent. The ORA, UCAN and other intervenors have filed testimony recommending significantly lower RORs. The ORA is recommending an electric ROR of 7.68 percent and a natural gas ROR of 8.01 percent. A CPUC decision is expected during the second quarter of 1999. In 1998, SDG&E's electric and natural gas distribution operations were authorized to earn an ROE of 11.6 percent and an ROR of 9.35 percent, unchanged from 1997. In addition, the authorized rates of return on nuclear and non-nuclear generating assets are 7.14 percent and 6.75 percent, respectively. Transactions Between Utilities and Affiliated Companies On December 16, 1997, the CPUC adopted rules, effective January 1, 1998, establishing uniform standards of conduct governing the manner in which IOUs conduct business with their energy-related affiliates. The objective of the affiliate-transaction rules is to ensure that these affiliates do not gain an unfair advantage over other competitors in the marketplace and that utility customers do not subsidize affiliate activities. The rules establish standards relating to non-discrimination, disclosure and information exchange, and separation of activities. The CPUC excluded utility-to-utility transactions between SDG&E and SoCalGas from the affiliate-transaction rules in its March 1998 decision approving the PE/Enova Business Combination (see Note 1). NOTE 13: SEGMENT INFORMATION The Company has three separately managed reportable segments: electric transmission and distribution, electric generation, and natural gas service. The accounting policies of the segments are the same as those described in Note 2 and segment performance is evaluated by management based on reported operating income. Intersegment transactions are generally recorded the same as sales or transactions with third parties. Interest expense and income tax expense are not allocated to the reportable segments. Interest revenue ($40 million, $9 million and $7 million for the years ended December 31, 1998, 1997 and 1996, respectively) is included in other income on the Statements of Consolidated Income herein. It is not allocated to the reportable segments and, therefore, is not presented in the tables below. - ----------------------------------------------------------------------- For the year ended December 31, (Dollars in millions) 1998 1997 1996 - ----------------------------------------------------------------------- Revenues: Transmission & distribution $ 1,555 $ 1,202 $ 1,095 Electric Generation 810 567 496 Natural Gas 384 398 348 ------------------------------------- Total $ 2,749 $ 2,167 $ 1,939 ------------------------------------- Depreciation and amortization: Transmission & distribution $ 134 $ 128 $ 122 Electric Generation 430 159 157 Natural Gas 39 37 35 ------------------------------------- Total $ 603 $ 324 $ 314 ------------------------------------- Segment Income: Transmission & distribution $ 302 $ 349 $ 358 Electric Generation 54 106 95 Natural Gas 63 79 58 ------------------------------------- Total segment income 419 534 511 ------------------------------------- Interest expense (116) (86) (91) Income tax expense (142) (219) (198) Nonoperating income 30 9 -- ------------------------------------- Net income $ 191 $ 238 $ 222 ------------------------------------- Capital Expenditures: Transmission & distribution $ 173 $ 147 $ 155 Electric Generation 18 14 12 Natural Gas 36 36 42 ------------------------------------- Total $ 227 $ 197 $ 209 ------------------------------------- - ----------------------------------------------------------------------- At December 31, or for the year then ended (Dollars in millions) 1998 1997 1996 - ----------------------------------------------------------------------- Assets: Transmission & distribution $ 2,518 $ 2,257 $ 2,318 Electric Generation 685 1,051 1,052 Natural Gas 553 592 626 All other 501 754 165 ------------------------------------- Total $ 4,257 $ 4,654 $ 4,161 ------------------------------------- Geographic Information: Long-lived assets United States $ 2,300 $ 2,359 $ 2,409 ------------------------------------- Operating Revenues: United States $ 2,749 $ 2,159 $ 1,933 Mexico -- 8 6 ------------------------------------- Total $ 2,749 $ 2,167 $ 1,939 - ----------------------------------------------------------------------- NOTE 14: SUBSEQUENT EVENT On February 22, 1999, Sempra Energy and KN Energy, Inc. (KN Energy) announced that their respective boards of directors approved Sempra Energy's acquisition of KN Energy, subject to approval by the shareholders of both companies and by various federal and state regulatory agencies. If the transaction is approved, holders of KN Energy common stock will receive 1.115 shares of Sempra Energy common stock or $25 in cash, or some combination thereof, for each share of KN Energy common stock. In the aggregate, the cash portion of the transaction will constitute not more than 30 percent of the total consideration of $1.7 billion. The companies anticipate that the closing will occur in six to eight months. The transaction will be treated as a purchase for accounting purposes. NOTE 15: QUARTERLY FINANCIAL DATA (UNAUDITED) Quarter ended ----------------------------------------------------- Dollars in millions March 31 June 30 September 30 December 31 - ---------------------------------------------------------------------------------- 1998 Operating revenues $ 606 $ 683 $ 815 $ 645 Operating expenses 529 638 727 569 --------------------------------------------------- Operating income $ 77 $ 45 $ 88 $ 76 --------------------------------------------------- Net income $ 50 $ 27 $ 64 $ 50 Dividends on preferred stock 1 2 2 1 --------------------------------------------------- Net income applicable to common shares $ 49 $ 25 $ 62 $ 49 =================================================== 1997 Operating revenues $ 495 $ 492 $ 566 $ 614 Operating expenses 432 414 480 524 --------------------------------------------------- Operating income $ 63 $ 78 $ 86 $ 90 --------------------------------------------------- Net income $ 42 $ 55 $ 65 $ 76 Dividends on preferred stock 2 1 2 1 --------------------------------------------------- Net income applicable to common shares $ 40 $ 54 $ 63 $ 75 =================================================== Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required on Identification of Directors is incorporated by reference from "Election of Directors" in the Information Statement prepared for the May 1999 annual meeting of shareholders. The information required on the Company's executive officers is set forth in Item 4 herein. ITEM 11. EXECUTIVE COMPENSATION The information required by Item 11 is incorporated by reference from "Election of Directors" and "Executive Compensation" in the Information Statement prepared for the May 1999 annual meeting of shareholders. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT The information required by Item 12 is incorporated by reference from "Election of Directors" in the Information Statement prepared for the May 1999 annual meeting of shareholders. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. None. PART IV 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 Page in This Report Independent Auditors' Report . . . . . . . . . . . . . . 35 Statements of Consolidated Income for the years ended December 31, 1998, 1997 and 1996 . . . . . . . . 36 Consolidated Balance Sheets at December 31, 1998 and 1997. . . . . . . . . . . . . . . . . . . . . 37 Statements of Consolidated Cash Flows for the years ended December 31, 1998, 1997 and 1996 . . . . . 38 Statements of Consolidated Changes in Shareholders' Equity for the years ended December 31, 1998, 1997 and 1996 . . . . . . . . . . . 40 Notes to Consolidated Financial Statements . . . . . . . 41 Quarterly Financial Data (Unaudited) . . . . . . . . . . 64 2. Financial statement schedules Schedules for which provision is made in Regulation S-X are not required under the instructions contained therein, are inapplicable, or the information is included in the notes to the Consolidated Financial Statements herein. 3. Exhibits See Exhibit Index on page 68 of this report. (b) Reports on Form 8-K The following reports on Form 8-K were filed after September 30, 1998: A Current Report on Form 8-K filed November 4, 1998 discussed the defeat of the Voter Initiative which sought to amend or repeal California electric industry restructuring legislation in various respects and announced the date of the 1999 Annual Meeting of Shareholders. A Current Report on Form 8-K filed December 16, 1998 announced the execution of contracts for the sale of SDG&E's fossil-fueled power plants. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized. SAN DIEGO GAS & ELECTRIC COMPANY By: /s/ Edwin A. Guiles --------------------------------- Edwin A. Guiles President and Chief Financial Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report is signed below by the following persons on behalf of the Registrant in the capacities and on the dates indicated. Name/Title Signature Date Principal Executive Officers: Edwin A. Guiles President, Chief Financial Officer /s/ Edwin A. Guiles March 2, 1999 Principal Financial Officer: Edwin A. Guiles President, Chief Financial Officer /s/ Edwin A. Guiles March 2, 1999 Principal Accounting Officer: Edwin A. Guiles President, Chief Financial Officer /s/ Edwin A. Guiles March 2, 1999 Directors: Warren I. Mitchell Chairman /s/ Warren I. Mitchell March 2, 1999 Hyla H. Bertea Director /s/ Hyla H. Bertea March 2, 1999 Ann Burr Director /s/ Ann Burr March 2, 1999 Herbert L. Carter Director /s/ Herbert L. Carter March 2, 1999 Richard A. Collato Director /s/ Richard A. Collato March 2, 1999 Daniel W. Derbes Director /s/ Daniel W. Derbes March 2, 1999 Wilford D. Godbold, Jr. Director /s/ Wilford D. Godbold, Jr. March 2, 1999 Robert H. Goldsmith Director /s/ Robert H. Goldsmith March 2, 1999 William D. Jones Director /s/ William D. Jones March 2, 1999 Ignacio E. Lozano, Jr. Director /s/ Ignacio E. Lozano, Jr. March 2, 1999 Ralph R. Ocampo Director /s/ Ralph R. Ocampo March 2, 1999 William G. Ouchi Director /s/ William G. Ouchi March 2, 1999 Richard J. Stegemeier Director /s/ Richard J. Stegemeier March 2, 1999 Thomas C. Stickel Director /s/ Thomas C. Stickel March 2, 1999 Diana L. Walker Director /s/ Diana L. Walker March 2, 1999 EXHIBIT INDEX The Forms 8-K, 10-K and 10-Q referred to herein were filed under Commission File Number 1-3779 (SDG&E), Commission File Number 1- 11439 (Enova Corporation, Commission File Number 1-14201 (Sempra Energy) and/or Commission File Number 333-30761 (SDG&E Funding LLC). Exhibit 1 -- Underwriting Agreements 1.01 Underwriting Agreement dated December 4, 1997 (Incorporated by reference from Form 8-K filed by SDG&E Funding LLC on December 23, 1997 (Exhibit 1.1)). Exhibit 3 -- Bylaws and Articles of Incorporation Bylaws 3.01 Restated Bylaws of San Diego Gas & Electric as of September 1, 1998. Articles of Incorporation 3.02 Amended and Restated Articles of Incorporation of San Diego Gas & Electric Company (Incorporated by reference from the SDG&E Form 10-Q for the three months ended March 31, 1994.(Exhibit 3.1)) Exhibit 4 -- Instruments Defining the Rights of Security Holders, Including Indentures The Company agrees to furnish a copy of each such instrument to the Commission upon request. 4.01 Mortgage and Deed of Trust dated July 1, 1940. (Incorporated by reference from SDG&E Registration No. 2-49810, Exhibit 2A.) 4.02 Second Supplemental Indenture dated as of March 1, 1948. (Incorporated by reference from SDG&E Registration No. 2-49810, Exhibit 2C.) 4.03 Ninth Supplemental Indenture dated as of August 1, 1968. (Incorporated by reference from SDG&E Registration No. 2-68420, Exhibit 2D.) 4.04 Tenth Supplemental Indenture dated as of December 1, 1968. (Incorporated by reference from SDG&E Registration No. 2-36042, Exhibit 2K.) 4.05 Sixteenth Supplemental Indenture dated August 28, 1975. (Incorporated by reference from SDG&E Registration No. 2-68420, Exhibit 2E.) 4.06 Thirtieth Supplemental Indenture dated September 28, 1983. (Incorporated by reference from SDG&E Registration No. 33-34017, Exhibit 4.3.) Exhibit 10 -- Material Contracts 10.01 Transition Property Purchase and Sale Agreement dated December 16, 1997 (Incorporated by reference from Form 8-K filed by SDG&E Funding LLC on December 23, 1997, Exhibit 10.1.) 10.02 Transition Property Servicing Agreement dated December 16, 1997 (Incorporated by reference from Form 8-K filed by SDG&E Funding LLC on December 23, 1997, Exhibit 10.2.) Compensation 10.03 Sempra Energy Supplemental Executive Retirement Plan as amended and restated effective July 1, 1998 (1998 Sempra Energy Form 10-K Exhibit 10.09). 10.04 Sempra Energy Executive Incentive Plan effective June 1, 1998 (1998 Sempra Energy Form 10-K Exhibit 10.11). 10.05 Sempra Energy Executive Deferred Compensation Agreement effective June 1, 1998(1998 Sempra Energy Form 10-K Exhibit 10.12). 10.06 Sempra Energy 1998 Long Term Incentive Plan (Incorporated by reference from the Registration Statement on Form S-8 Sempra Energy Registration No. 333-56161 dated June 5, 1998). 10.07 Enova Corporation 1986 Long-Term Incentive Plan amended and restated as the Sempra Energy 1986 Long-Term Incentive Plan (Incorporated by reference from the Registration Statement on Form S-8 Sempra Energy Registration No. 333-56161). 10.08 Pacific Lighting Corporation Stock Incentive Plan amended and restated as the Sempra Energy Stock Incentive Plan (Incorporated by reference from the Registration Statement on Form S-8 Sempra Energy Registration No. 333-56161). 10.09 Pacific Enterprises Employee Stock Option Plan amended and restated as the Sempra Energy Employee Stock Option Plan (Incorporated by reference from the Registration Statement on Form S-8 Sempra Energy Registration No. 333-56161). 10.10 Form of Amendment to San Diego Gas & Electric Company Deferred Compensation Agreements for Officers #1 and #3 (1996 Form 10-K Exhibit 10.6). 10.11 Form of Enova Corporation 1998 Deferred Compensation Agreement for Officers #1 (1998 compensation, 1998 bonus) (1997 Enova Form 10-K Exhibit 10.15). 10.12 Form of Enova Corporation 1997 Deferred Compensation Agreement for Officers #1 (1997 compensation, 1998 bonus) (1996 Form 10-K Exhibit 10.7). 10.13 Form of San Diego Gas & Electric Company Deferred Compensation Agreement for Officers #1 (1996 compensation, 1997 bonus)(1995 SDG&E Form 10-K Exhibit 10.1). 10.14 Agreement for Officers #3 (1997 Enova Form 10-K Exhibit 10.12). 10.15 Form of Enova Corporation 1997 Deferred Compensation Agreement for Officers #3 (1997 compensation, 1998 bonus)(1996 Form 10-K Exhibit 10.10). 10.16 Form of San Diego Gas & Electric Company Deferred Compensation Agreement for Officers #3 (1996 compensation, 1997 bonus)(1995 SDG&E Form 10-K Exhibit 10.3). 10.17 Form of Enova Corporation 1998 Deferred Compensation Agreement for Nonemployee Directors (1997 Enova Form 10-K Exhibit 10.16). 10.18 Form of Enova Corporation 1997 Deferred Compensation Agreement for Nonemployee Directors (1996 Form 10-K Exhibit 10.13). 10.19 Compensation Agreement for Nonemployee Directors (1996 compensation)(1995 SDG&E Form 10-K Exhibit 10.5). 10.20 Form of Enova Corporation 1986 Long-Term Incentive Plan 1997 restricted stock award agreement (1997 Enova Form 10-K Exhibit 10.18). 10.21 Form of Enova Corporation 1986 Long-Term Incentive Plan 1996 restricted stock award agreement (1996 Form 10-K Exhibit 10.16). 10.22 Form of San Diego Gas & Electric Company 1986 Long-Term Incentive Plan 1995 restricted stock award agreement (1995 SDG&E Form 10-K Exhibit 10.7). 10.23 Form of San Diego Gas & Electric Company 1986 Long-Term Incentive Plan Special 1995 restricted stock award agreement (1995 SDG&E Form 10-K Exhibit 10.8). 10.24 Form of San Diego Gas & Electric Company 1986 Long-Term Incentive Plan 1994 restricted stock award agreement two- year vesting (1995 SDG&E Form 10-K Exhibit 10.9). 10.25 Form of San Diego Gas & Electric Company 1986 Long-Term Incentive Plan 1994 restricted stock award agreement (1994 SDG&E Form 10-K Exhibit 10.4). 10.26 Amended 1986 Long-Term Incentive Plan, amended and restated effective April 25, 1995 (SDG&E's Amendment No. 2 to Form S-4 filed February 28, 1995). 10.27 Amended 1986 Long-Term Incentive Plan, Restatement as of October 25, 1993 (1993 SDG&E Form 10-K Exhibit 10.6). 10.28 San Diego Gas & Electric Company Severance Plan effective October 22, 1996 (1996 Form 10-K Exhibit 10.24). 10.29 San Diego Gas & Electric Company Severance Plan effective on the date of the Enova Corporation -- Pacific Enterprises business combination (1996 Form 10-K Exhibit 10.25). 10.30 San Diego Gas & Electric Company Retirement Plan for Directors, restated as of October 24, 1994 (1994 SDG&E Form 10-K Exhibit 10.5). 10.31 Executive Incentive Plan dated April 23, 1985 (1991 SDG&E Form 10-K Exhibit 10.39). 10.32 Employment agreement between San Diego Gas & Electric Company and Thomas A. Page, dated June 15, 1988 (1988 SDG&E Form 10-K Exhibit 10E). 10.33 Supplemental Pension Agreement with Thomas A. Page, dated as of April 3, 1978 (1988 SDG&E Form 10-K Exhibit 10V). 10.34 Supplemental Executive Retirement Plan restated as of July 1, 1994 (1994 SDG&E Form 10-K Exhibit 10.14). Financing 10.35 Loan agreement with the City of Chula Vista in connection with the issuance of $25 million of Industrial Development Bonds, dated as of October 1, 1997 (Enova 1997 Form 10-K Exhibit 10.34). 10.36 Loan agreement with the City of Chula Vista in connection with the issuance of $38.9 million of Industrial Development Bonds, dated as of August 1, 1996 (1996 Form 10-K Exhibit 10.31). 10.37 Loan agreement with the City of Chula Vista in connection with the issuance of $60 million of Industrial Development Bonds, dated as of November 1, 1996 (1996 Form 10-K Exhibit 10.32). 10.38 Loan agreement with City of San Diego in connection with the issuance of $57.7 million of Industrial Development Bonds, dated as of June 1, 1995 (June 30, 1995 SDG&E Form 10-Q Exhibit 10.3). 10.39 Loan agreement with the City of San Diego in connection with the issuance of $92.9 million of Industrial Development Bonds 1993 Series C dated as of July 1, 1993 (June 30, 1993 SDG&E Form 10-Q Exhibit 10.2). 10.40 Loan agreement with the City of San Diego in connection with the issuance of $70.8 million of Industrial Development Bonds 1993 Series A dated as of April 1, 1993 (March 31, 1993 SDG&E Form 10-Q Exhibit 10.3). 10.41 Loan agreement with the City of San Diego in connection with the issuance of $118.6 million of Industrial Development Bonds dated as of September 1, 1992 (Sept. 30, 1992 SDG&E Form 10-Q Exhibit 10.1). 10.42 Loan agreement with the City of Chula Vista in connection with the issuance of $250 million of Industrial Development Bonds, dated as of December 1, 1992 (1992 SDG&E Form 10-K Exhibit 10.5). 10.43 Loan agreement with the City of San Diego in connection with the issuance of $25 million of Industrial Development Bonds, dated as of September 1, 1987 (1992 SDG&E Form 10-K Exhibit 10.6). 10.44 Loan agreement with the California Pollution Control Financing Authority in connection with the issuance of $129.82 million of Pollution Control Bonds, dated as of June 1, 1996 (1996 Form 10-K Exhibit 10.41). 10.45 Loan agreement with the California Pollution Control Financing Authority in connection with the issuance of $60 million of Pollution Control Bonds dated as of June 1, 1993 (June 30, 1993 SDG&E Form 10-Q Exhibit 10.1). 10.46 Loan agreement with the California Pollution Control Financing Authority, dated as of December 1, 1991, in connection with the issuance of $14.4 million of Pollution Control Bonds (1991 SDG&E Form 10-K Exhibit 10.11). Nuclear 10.47 Uranium enrichment services contract between the U.S. Department of Energy (DOE assigned its rights to the U.S. Enrichment Corporation, a U.S. government-owned corporation, on July 1, 1993) and Southern California Edison Company, as agent for SDG&E and others; Contract DE-SC05-84UEO7541, dated November 5, 1984, effective June 1, 1984, as amended (1991 SDG&E Form 10-K Exhibit 10.9). 10.48 Fuel Lease dated as of September 8, 1983 between SONGS Fuel Company, as Lessor and San Diego Gas & Electric Company, as Lessee, and Amendment No. 1 to Fuel Lease, dated September 14, 1984 and Amendment No. 2 to Fuel Lease, dated March 2, 1987 (1992 SDG&E Form 10-K Exhibit 10.11). 10.49 Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station, approved November 25, 1987 (1992 SDG&E Form 10-K Exhibit 10.7). 10.50 Amendment No. 1 to the Qualified CPUC Decommissioning Master Trust Agreement dated September 22, 1994 (see Exhibit 10.49 herein)(1994 SDG&E Form 10-K Exhibit 10.56). 10.51 Second Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.49 herein)(1994 SDG&E Form 10-K Exhibit 10.57). 10.52 Third Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.49 herein)(1996 Form 10-K Exhibit 10.59). 10.53 Fourth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.49 herein)(1996 Form 10-K Exhibit 10.60). 10.54 Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station, approved November 25, 1987 (1992 SDG&E Form 10-K Exhibit 10.8). 10.55 First Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.54 herein)(1996 Form 10-K Exhibit 10.62). 10.56 Second Amendment to the San Diego Gas & Electric Company Nuclear Facilities Non-Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.54 herein)(1996 Form 10-K Exhibit 10.63). 10.57 Second Amended San Onofre Agreement among Southern California Edison Company, SDG&E, the City of Anaheim and the City of Riverside, dated February 26, 1987 (1990 SDG&E Form 10-K Exhibit 10.6). 10.58 U. S. Department of Energy contract for disposal of spent nuclear fuel and/or high-level radioactive waste, entered into between the DOE and Southern California Edison Company, as agent for SDG&E and others; Contract DE-CR01-83NE44418, dated June 10, 1983 (1988 SDG&E Form 10-K Exhibit 10N). Purchased Power 10.59 Public Service Company of New Mexico and San Diego Gas & Electric Company 1988-2001 100 mw System Power Agreement dated November 4, 1985 and Letter of Agreement dated April 28, 1986, June 4, 1986 and June 18, 1986 (1988 SDG&E Form 10-K Exhibit 10H). 10.60 San Diego Gas & Electric Company and Portland General Electric Company Long-Term Power Sale and Transmission Service agreements dated November 5, 1985 (1988 SDG&E Form 10-K Exhibit 10I). Natural Gas Commodity, Transportation and Storage 10.61 Master Services Contract, Schedule J, Transaction Based Storage Service Agreement dated April 1, 1999 and expiring March 31, 2000 between San Diego Gas & Electric Company and Southern California Gas Company. 10.62 Master Services Contract, Schedule J, Transaction Based Storage Service Agreement dated April 1, 1998 and expiring March 31, 1999 Between San Diego Gas & Electric Company and Southern California Gas Company. 10.63 Master Services Contract (Intrastate Transportation-utility electric generation), dated July 1,1998 and expiring July 1, 2000 between San Diego Gas & Electric Company and Southern California Gas Company. 10.64 Master Services Contract (Intrastate Transportation),dated July 1, 1998 and expiring July 1, 2000 between San Diego Gas & Electric Company and Southern California Gas Company. 10.65 Long-term Natural Gas Storage Service Agreement dated January 12, 1994 between Southern California Gas Company and SDG&E (1994 SDG&E Form 10-K Exhibit 10.42). 10.66 Amendment to San Diego Gas & Electric Company and Southern California Gas Company Restated Long-Term Wholesale Natural Gas Service Contract dated March 26, 1993 (1993 SDG&E Form 10-K Exhibit 10.53). 10.67 San Diego Gas & Electric Company and Southern California Gas Company Restated Long-Term Wholesale Natural Gas Service Contract, dated September 1, 1990 (1990 SDG&E Form 10-K Exhibit 10.9). 10.68 Third Amending Agreement, dated November 1, 1997 between Husky Oil Operations Limited and San Diego Gas & Electric Company (1997 Enova Corporation Form 10-K Exhibit 10.50). 10.69 Second Amending Agreement, dated January 1, 1997 between Husky Oil Operations Limited and San Diego Gas & Electric Company (1997 Enova Corporation Form 10-K Exhibit 10.51). 10.70 Amending Agreement dated November 1, 1994 between Husky Oil Operations Limited and San Diego Gas & Electric Company (1997 Enova Corporation Form 10-K Exhibit 10.52). 10.71 Gas Purchase Agreement, dated March 12, 1991 between Husky Oil Operations Limited and San Diego Gas & Electric Company (1991 SDG&E Form 10-K Exhibit 10.1). 10.72 Gas Purchase Agreement, dated March 12, 1991 between Canadian Hunter Marketing Limited and San Diego Gas & Electric Company (1991 SDG&E Form 10-K Exhibit 10.2). 10.73 Gas Purchase Agreement, dated March 12, 1991 between Bow Valley Industries Limited and San Diego Gas & Electric Company (1991 SDG&E Form 10-K Exhibit 10.3). 10.74 Gas Purchase Agreement, dated March 12, 1991 between Summit Resources Limited and San Diego Gas & Electric Company (1991 SDG&E Form 10-K Exhibit 10.4). 10.75 Service Agreement Applicable to Firm Transportation Service under Rate Schedule FS-1, dated May 31, 1991 between Alberta Natural Gas Company Ltd. and San Diego Gas & Electric Company (1991 SDG&E Form 10-K Exhibit 10.5). 10.76 Amendment to Firm Transportation Service Agreement, dated December 2, 1996, between Pacific Gas and Electric Company and San Diego Gas & Electric Company (1997 Enova Corporation Form 10-K Exhibit 10.58). 10.77 Firm Transportation Service Agreement, dated December 31, 1991 between Pacific Gas and Electric Company and San Diego Gas & Electric Company (1991 SDG&E Form 10-K Exhibit 10.7). 10.78 Firm Transportation Service Agreement, dated October 13, 1994 between Pacific Gas Transmission Company and San Diego Gas & Electric Company (1997 Enova Corporation Form 10-K Exhibit 10.60). Other 10.79 U. S. Navy contract for electric service, Contract N62474-70-C-1200-P00414, dated September 29, 1988 (1988 SDG&E Form 10-K Exhibit 10C). 10.80 Lease agreement dated as of March 25, 1992 with American National Insurance Company as lessor of an office complex at Century Park (1994 SDG&E Form 10-K Exhibit 10.70). 10.81 Lease agreement dated as of June 15, 1978 with Lloyds Bank California, as owner-trustee and lessor - Exhibit B to financing agreement of SDG&E's Encina Unit 5 equipment trust (1988 SDG&E Form 10-K Exhibit 10W). 10.82 Amendment to Lease agreement dated as of July 1, 1993 with Sanwa Bank California, as owner-trustee and lessor - Exhibit B to secured loan agreement of SDG&E's Encina Unit 5 equipment trust (See Exhibit 10.81 herein)(1994 SDG&E Form 10-K Exhibit 10.72). 10.83 Lease agreement dated as of July 14, 1975 with New England Mutual Life Insurance Company, as lessor (1991 SDG&E Form 10-K Exhibit 10.42). 10.84 Assignment of Lease agreement dated as of November 19, 1993 to Shapery Developers as lessor by New England Mutual Life Insurance Company (See Exhibit 10.83 herein)(1994 SDG&E Form 10-K Exhibit 10.74). Exhibit 12 -- Statement Re: Computation Of Ratios 12.01 Computation of Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends for the years ended December 31, 1998, 1997, 1996, 1995 and 1994. Exhibit 21 - Subsidiaries - SDG&E Funding LLC, a wholly owned subsidiary of SDG&E Exhibit 23 - Consents of Experts and Counsel 23.01 Independent Auditors' Consent. Exhibit 27 - Financial Data Schedule 27.01 Financial Data Schedule for the year ended December 31, 1998. GLOSSARY AB 1890 Assembly Bill 1890 - California's electric restructuring law AFUDC Allowance for Funds Used During Construction APCD Air Pollution Control District BCAP Biennial Cost Allocation Proceeding Bcf Billion Cubic Feet (of natural gas) BTU British Thermal Unit CEC California Energy Commission CFE Comision Federal de Electricidad CPUC California Public Utilities Commission CTC Competition Transition Charge DOE Department of Energy DGN Distribuidora de Gas Natural DTSC Department of Toxic Substances Control Edison Southern California Edison Company EMF Electric and Magnetic Fields Enova Enova Corporation, the Company's parent FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission GRC General Rate Case IDBs Industrial Development Bonds IOUs Investor-Owned Utilities ISO Independent System Operator IT Information Technology Kv Kilovolt Kwhr Kilowatt Hour Mcf Thousand Cubic Feet (of natural gas) Mmcfd Million Cubic Feet (of natural gas) per day Mw Megawatt NPDES National Pollutant Discharge Elimination System NRC Nuclear Regulatory Commission ORA Office of Ratepayer Advocates PBR Performance-Based Ratemaking PCB Polychlorinated Biphenyl PE Pacific Enterprises PG&E Pacific Gas and Electric Company PGE Portland General Electric Company PNM Public Service Company of New Mexico PRP Potential Responsible Party PX Power Exchange QF Qualifying Facility ROE Return on Equity ROR Rate of Return RWQCB Regional Water Quality Control Board SDG&E San Diego Gas & Electric Company SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards SoCalGas Southern California Gas Company, an affiliate of the Company SONGS San Onofre Nuclear Generating Station Southwest Powerlink A transmission line connecting San Diego to Phoenix and intermediate points SWRCB State Water Resources Control Board UEG Utility electric generation VaR Value at Risk WSPP Western Systems Power Pool 71 78

EXHIBIT 3.01 BYLAWS OF SAN DIEGO GAS & ELECTRIC COMPANY As of September 1, 1998 ARTICLE ONE Corporate Management The business and affairs of the corporation shall be managed, and all corporate powers shall be exercised, by or under the direction of the Board of Directors ("the Board"), subject to the Articles of Incorporation and the California Corporations Code. ARTICLE TWO Officers Section 1. Designation. The officers of the corporation shall consist of a Chairman of the Board ("Chairman") or a President, or both, one or more Vice Presidents, a Secretary, one or more Assistant Secretaries, a Treasurer, one or more Assistant Treasurers, a Controller, one or more Assistant Controllers, and such other officers as the Board may from time to time elect. Any two or more of such offices may be held by the same person. Section 2. Term. The officers shall be elected by the Board as soon as possible after the annual meeting of the Shareholders, and shall hold office for one year or until their successors are duly elected. Any officers may be removed from office at any time, with or without cause, by the vote of a majority of the authorized number of Directors. The Board may fill vacancies or elect new officers at any time. Section 3. Chairman. The Chairman, or any officer designated by the Chairman, shall preside over meetings of the Shareholders and of the Board. The Chairman shall perform all other duties designated by the Board. Section 4. The President. The President shall have the general management and direction of the affairs of the corporation, subject to the control of the Board. In the absence or disability of the Chairman, the President shall perform the duties and exercise the powers of the Chairman. Section 5. Vice Presidents. The Vice Presidents, one of whom shall be the Chief Financial Officer, shall have such duties as the President or the Board shall designate. Section 6. Chief Financial Officer. The Chief Financial Officer shall be responsible for the issuance of securities and the management of the corporation's cash, receivables and temporary investments. Section 7. Secretary and Assistant Secretary. The Secretary shall attend all meetings of the Shareholders and the Board, keep a true and accurate record of the proceedings of all such meetings and attest the same by his or her signature, have charge of all books, documents and papers which appertain to the office, have custody of the corporate seal and affix it to all papers and documents requiring sealing, give all notices of meetings, have the custody of the books of stock certificates and transfers, issue all stock certificates, and perform all other duties usually appertaining to the office and all duties designated by the bylaws, the President or the Board. In the absence of the Secretary, any Assistant Secretary may perform the duties and shall have the powers of the Secretary. Section 8. Treasurer and Assistant Treasurer. The Treasurer shall perform all duties usually appertaining to the office and all duties designated by the President or the Board. In the absence of the Treasurer, any Assistant Treasurer may perform the duties and shall have all the powers of the Treasurer. Section 9. Controller and Assistant Controller. The Controller shall be responsible for establishing financial control policies for the corporation, shall be its principal accounting officer, and shall perform all duties usually appertaining to the office and all duties designated by the President or the Board. In the absence of the Controller, any Assistant Controller may perform the duties and shall have all the powers of the Controller. Section 10. Chief Executive Officer. Either the Chairman or the President shall be the Chief Executive Officer. Section 11. Chief Operating Officer. Either the President or any Vice President shall be the Chief Operating Officer. ARTICLE THREE Directors Section 1. Number. The authorized number of Directors shall be from a minimum of seven to a maximum of seventeen, unless changed by the vote or written consent of holders of a majority of outstanding shares entitled to vote. The Board of Directors shall fix by resolution the number of Directors comprising the Board within the stated minimum and maximum number at its discretion and without Shareholder approval. Section 2. Election. A Board shall be elected at each annual meeting of the Shareholders, at any adjournment thereof, or at any special meeting of the Shareholders called for that purpose. The Directors shall hold office for one year or until their successors are duly elected. Any candidate nominated by management for election to the Board shall be so nominated without regard to his or her sex, race, color or creed. Section 3. Vacancies. Vacancies in the Board may be filled by a majority of the remaining Directors, though less than a quorum, and each Director so elected shall hold office for the unexpired term and until his or her successor is elected. Section 4. Compensation. Members of the Board shall receive such compensation as the Board may from time to time determine. Section 5. Regular Meetings. A regular meeting of the Board shall be held without other notice than this bylaw immediately after each annual meeting of the Shareholders, and at such other times as provided for by resolution, at the principal office of the corporation. The Board may cancel, or designate a different date, time or place for any regular meeting. Section 6. Special Meetings. Special meetings of the Board may be called at any time by the Chairman, the President or any two Directors. Section 7. Notice of Meetings. Written notice shall be given to each Director of the date, time and place of each regular meeting and each special meeting of the Board. If given by mail, such notice shall be mailed to each Director at least four days before the date of such meeting, or such notice may be given to each Director personally or by telegram at least 48 hours before the time of such meeting. Every notice of special meeting shall state the purpose for which such meeting is called. Notice of a meeting need not be given to any Director who signs a waiver of notice, whether before or after the meeting, or who attends the meeting without protesting, prior thereto or at its commencement, the lack of notice to such Director. Section 8. Quorum. A majority of the authorized number of Directors shall be necessary to constitute a quorum for the transaction of business, and every act or decision of a majority of the Directors present at a meeting at which a quorum is present shall be valid as the act of the Board, provided that a meeting at which a quorum is initially present may continue to transact business, notwithstanding the withdrawal of Directors, if any action taken is approved by at least a majority of the required quorum for such meeting. A majority of Directors present at any meeting, in the absence of a quorum, may adjourn to another time. Section 9. Action Upon Consent. Any action required or permitted to be taken by the Board may be taken without a meeting, if all members of the Board shall individually or collectively consent in writing to such action. Section 10. Telephonic Participation. Members of the Board may participate in a meeting through use of a conference telephone or similar communications equipment, so long as all members participating in the meeting can hear one another. Such participation constitutes presence in person at the meeting. Section 11. Directors Emeritus. The Board may from time to time elect one or more Directors Emeritus. Each Director Emeritus shall have the privilege of attending meetings of the Board, upon invitation of the Chairman or the President. No Director Emeritus shall be entitled to vote on any business coming before the Board or be counted as a member of the Board for any purpose whatsoever. ARTICLE FOUR Committees Section 1. Executive Committee. The Board shall appoint an Executive Committee. The Chairman shall be ex officio the Chairman thereof, unless the Board shall appoint another member as Chairman. The Executive Committee shall be composed of members of the Board, and shall at all times be subject to its control. The Executive Committee shall have all the authority of the Board, except with respect to: (a) The approval of any action which also requires Shareholders' approval. (b) The filling of vacancies on the Board or on any committee. (c) The fixing of compensation of the Directors for serving on the Board or on any committee. (d) The amendment or repeal of bylaws or the adoption of new bylaws. (e) The amendment or repeal of any resolution of the Board which by its express terms is not so amendable or repealable. (f) A distribution to the Shareholders. (g) The appointment of other committees of the Board or the members thereof. Section 2. Audit Committee. The Board shall appoint an Audit Committee comprised solely of Directors who are neither officers nor employees of the corporation and who are free from any relationship that, in the opinion of the Board, would interfere with the exercise of independent judgment as committee members. The Audit Committee shall review and make recommendations to the Board with respect to: (a) The engagement of an independent accounting firm to audit the corporation's financial statements and the terms of such engagement. (b) The policies and procedures for maintaining the corporation's books and records and for furnishing appropriate information to the independent auditor. (c) The evaluation and implementation of any recommendations made by the independent auditor. (d) The adequacy of the corporation's internal audit controls and related personnel. (e) Such other matters relating to the corporation's financial affairs and accounts as the Committee deems desirable. Section 3. Other Committees. The Board may appoint such other committees of its members as it shall deem desirable, and, within the limitations specified for the Executive Committee, may vest such committees with such powers and authorities as it shall see fit, and all such committees shall at all times be subject to its control. Section 4. Notice of Meetings. Notice of each meeting of any committee of the Board shall be given to each member of such committee, and the giving of such notice shall be subject to the same requirements as the giving of notice of meetings of the Board, unless the Board shall establish different requirements for the giving of notice of committee meetings. Section 5. Conduct of Meetings. The provisions of these bylaws with respect to the conduct of meetings of the Board shall govern the conduct of committee meetings. Written minutes shall be kept of all committee meetings. ARTICLE FIVE Shareholder Meetings Section 1. Annual Meeting. The annual meeting of the Shareholders shall be held on a date and at a time fixed by the Board. Section 2. Special Meetings. Special meetings of the Shareholders for any purpose whatsoever may be called at any time by the Chairman, the President, or the Board, or by one or more Shareholders holding not less than one-tenth of the voting power of the corporation. Section 3. Place of Meetings. All meetings of the Shareholders shall be held at the principal office of the corporation in San Diego, California, or at such other locations as may be designated by the Board. Section 4. Notice of Meetings. Written notice shall be given to each Shareholder entitled to vote of the date, time, place and general purpose of each meeting of Shareholders. Notice may be given personally, or by mail, or by telegram, charges prepaid, to the Shareholder's address appearing on the books of the corporation. If a Shareholder supplies no address to the corporation, notice shall be deemed to be given if mailed to the place where the principal office of the corporation is situated, or published at least once in some newspaper of general circulation in the county of said principal office. Notice of any meeting shall be sent to each Shareholder entitled thereto not less than 10 or more than 60 days before such meeting. Section 5. Voting. The Board may fix a time in the future not less than 10 or more than 60 days preceding the date of any meeting of Shareholders, or not more than 60 days preceding the date fixed for the payment of any dividend or distribution, or for the allotment of rights, or when any change or conversion or exchange of shares shall go into effect, as a record date for the determination of the Shareholders entitled to notice of and to vote at any such meeting or entitled to receive any such dividend or distribution, or any such allotment of rights, or to exercise the rights in respect to any such change, conversion, or exchange of shares. In such case only Shareholders of record at the close of business on the date so fixed shall be entitled to notice of and to vote at such meeting or to receive such dividend, distribution or allotment of rights, or to exercise such rights, as the case may be, notwithstanding any transfer of any shares on the books of the corporation after any record date fixed as aforesaid. The Board may close the books of the corporation against any transfer of shares during the whole or any part of such period. Section 6. Quorum. At any Shareholders' meeting a majority of the shares entitled to vote must be represented in order to constitute a quorum for the transaction of business, but a majority of the shares present, or represented by proxy, though less than a quorum, may adjourn the meeting to some other date, and from day to day or from time to time thereafter until a quorum is present. Section 7. Elimination of Cumulative Voting. No holder of any class of stock of the corporation shall be entitled to cumulate votes at any election of Directors of the corporation. ARTICLE SIX Certificate of Shares Section 1. Form. Certificates for Shares of the corporation shall state the name of the registered holder of the Shares represented thereby, and shall be signed by the Chairman or Vice Chairman or the President or a Vice President, and by the Chief Financial Officer or an Assistant Treasurer or the Secretary or an Assistant Secretary. Any such signature may be by facsimile thereof. Section 2. Surrender. Upon a surrender to the Secretary, or to a transfer agent or transfer clerk of the corporation, of a Certificate of Shares duly endorsed or accompanied by proper evidence of succession, assignment or authority to transfer, the corporation shall issue a new certificate to the party entitled thereto, cancel the old certificate and record the transaction upon its books. Section 3. Right of Transfer. When a transfer of shares on the books is requested, and there is a reasonable doubt as to the rights of the persons seeking such transfer, the corporation, or its transfer agent or transfer clerk, before entering the transfer of the shares on its books or issuing any certificate therefor, may require from such person reasonable proof of his or her rights, and, if there remains a reasonable doubt in respect thereto, may refuse a transfer unless such person shall give adequate security or a bond of indemnity executed by a corporate surety, or by two individual sureties, satisfactory to the corporation as to form, amount and responsibility of sureties. Section 4. Conflicting Claims. The corporation shall be entitled to treat the holder of record of any shares as the holder in fact thereof and shall not be bound to recognize any equitable or other claim to or interest in such shares on the part of any other person, whether or not it shall have express or other notice thereof, save as expressly provided by the laws of the State of California. Section 5. Loss, Theft and Destruction. In the case of the alleged loss, theft or destruction of any Certificate of Shares, another may be issued in its place as follows: (1) the owner of the lost, stolen or destroyed certificate shall file with the transfer agent of the corporation a duly executed Affidavit or Loss and Indemnity Agreement and Certificate of Coverage, accompanied by a check representing the cost of the bond as outlined in any blanket lost securities and administration bond previously approved by the Directors of the corporation and executed by a surety company satisfactory to them, which bond shall indemnify the corporation, its transfer agents and registrars; or (2) the Board may, in its discretion, authorize the issuance of a new certificate to replace a lost, stolen or destroyed certificate on such other terms and conditions as it may determine to be reasonable. ARTICLE SEVEN Indemnification of Agents of the Corporation Section 1. Definitions. For the purposes of this Article Seven, "agent" means any person who (i) is or was a Director, officer, employee or other agent of the corporation, (ii) is or was serving at the request of the corporation as a director, officer, employee or agent of another foreign or domestic corporation, partnership, joint venture, trust or other enterprise or (iii) was a director, officer, employee or agent of a foreign or domestic corporation which was a predecessor corporation of the corporation or of another enterprise at the request of such predecessor corporation; "proceeding" means any threatened, pending or completed action or proceeding, whether civil, criminal, administrative or investiga- tive; and "expenses" includes, without limitation, attorneys' fees and any expenses of establishing a right to indemnification under Sections 4 or 5(c) of this Article Seven. Section 2. Indemnification for Third Party Actions. The corporation shall have the power to indemnify any person who is or was a party, or is threatened to be made a party, to any proceeding (other than an action by or in the right of the corporation to procure a judgment in its favor) by reason of the fact that such person is or was an agent of the corporation against expenses, judgments, fines, settlements and other amounts actually and reasonably incurred in connection with such proceeding if such person acted in good faith and in a manner such person reasonably believed to be in the best interests of the corporation and, in the case of a criminal proceeding, had no reasonable cause to believe the conduct of such person was unlaw- ful. The termination of any proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent shall not, of itself, create a presumption that the person did not act in good faith and in a manner which the person reasonably believed to be in the best interests of the corporation or that the person had reasonable cause to believe that the per- son's conduct was unlawful. Section 3. Indemnification for Derivative Actions. The corporation shall have the power to indemnify any person who is or was a party, or is threatened to be made a party, to any threatened, pending or completed action by or in the right of the corporation to procure a judgment in its favor by reason of the fact that such person is or was an agent of the corporation against expenses actually and reasonably incurred by such person in connection with the defense or settlement of such action if such person acted in good faith and in a manner such person believed to be in the best interests of the corporation and its Shareholders. No indemnification shall be made under this Sec- tion 3: (a) In respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the corporation in the performance of such person's duty to the corporation and its Shareholders, unless and only to the extent that the court in which such proceeding is or was pending shall determine upon application that, in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for expenses and then only to the extent that the court shall determine; or (b) Of amounts paid in settling or otherwise disposing of a pending action without court approval; or (c) Of expenses incurred in defending a pending action which is settled or otherwise disposed of without court approval. Section 4. Successful Defense. Notwithstanding any other provision of this Article, to the extent that an agent of the corporation has been successful on the merits or otherwise (including the dismissal of an action without prejudice or the settlement of a proceeding or action without admission of liability) in defense of any proceeding referred to in Sections 2 or 3 of this Article, or in defense of any claim, issue or matter therein, he or she shall be indemnified against expenses (including attorneys' fees) actually and reasonably incurred in connection therewith. Section 5. Discretionary Indemnification. Except as provided in Section 4 of this Article Seven, any indemnification under Section 3 thereof shall be made by the corporation only if authorized in the specific case, upon a determination that indemnification of the agent is proper in the circumstances because the agent has met the applicable standard of conduct set forth in Section 3, by: (a) A majority vote of a quorum consisting of Directors who are not parties to such proceeding; (b) If such a quorum of Directors is not obtainable, by independent legal counsel in a written opinion; (c) Approval by the affirmative vote of a majority of the shares of this corporation represented and voting at a duly held meeting at which a quorum is present (which shares voting affirmatively also constitute at least a majority of the required quorum) or by the written consent of holders of a majority of the outstanding shares which would be entitled to vote at such meeting and, for such purpose, the shares owned by the person to be indemnified shall not be considered outstanding or entitled to vote; or (d) The court in which such proceeding is or was pending, upon application made by the corporation, the agent or the attorney or other person rendering services in connection with the defense, whether or not such application by said agent, attorney or other person is opposed by the corporation. Section 6: Advancement of Expenses. Expenses incurred in defending any proceeding may be advanced by the corporation prior to the final disposition of such proceeding upon receipt of an undertaking by or on behalf of the agent to repay such amount if it shall be determined ultimately that the agent is not entitled to be indemnified as authorized in this Article Seven. Section 7: Restriction on Indemnification. No indemnification or advance shall be made under this Article Seven, except as provided in Sections 4 and 6 thereof, in any circumstance where it appears: (a) That it would be inconsistent with a provision of the Articles of Incorporation of the corporation, its bylaws, a resolution of the Shareholders or an agreement in effect at the time of the accrual of the alleged cause of action asserted in the proceeding in which the expenses were incurred or other amounts were paid which prohibits or otherwise limits indemnification; or (b) That it would be inconsistent with any condition expressly imposed by a court in approving a settlement. Section 8: Non-Exclusive. In the absence of any other basis for indemnification of an agent, the corporation can indemnify such agent pursuant to this Article Seven. The indemnification provided by this Article Seven shall not be deemed exclusive of any other rights to which those seeking indemnification may be entitled under any statute, bylaw, agreement, vote of Shareholders or disinterested Directors or otherwise, both as to action in an official capacity and as to action in another capacity while holding such office. The rights to indemnification under this Article Seven shall continue as to a person who has ceased to be a Director, officer, employee, or agent and shall inure to the benefit of the heirs, executors, and administrators of the person. Nothing contained in this Section 8 shall affect any right to indemnification to which persons other than such Directors and officers may be entitled by contract or otherwise. Section 9: Expenses as a Witness. To the extent that any agent of the corporation is by reason of such position, or a position with another entity at the request of the corporation, a witness in any action, suit or proceeding, he or she shall be indemnified against all costs and expenses actually and reasonably incurred by him or her or on his or her behalf in connection therewith. Section 10: Insurance. The Board may purchase and maintain directors and officers liability insurance, at its expense, to protect itself and any Director, officer or other named or specified agent of the corporation or another corporation, partnership, joint venture, trust or other enterprise against any expense, liability or loss asserted against or incurred by the agent in such capacity or arising out of the agent's status as such, whether or not the corporation would have the power to indemnify the agent against such expense, liability or loss under the provisions of this Article Seven or under California Law. Section 11: Separability. Each and every paragraph, sentence, term and provision of this Article Seven is separate and distinct so that if any paragraph, sentence, term or provision hereof shall be held to be invalid or unenforceable for any reason, such invalidity or unenforceability shall not affect the validity or unenforceability of any other paragraph, sentence, term or provision hereof. To the extent required, any paragraph, sentence, term or provision of this Article may be modified by a court of competent jurisdiction to preserve its validity and to provide the claimant with, subject to the limitations set forth in this Article and any agreement between the corporation and claimant, the broadest possible indemnification permitted under applicable law. If this Article Seven or any portion thereof shall be invalidated on any ground by any court of competent jurisdiction, then the corporation shall nevertheless have the power to indemnify each Director, officer, employee, or other agent against expenses (including attorneys' fees), judgments, fines and amounts paid in settlement with respect to any action, suit, proceeding or investigation, whether civil, criminal or administrative, and whether internal or external, including a grand jury proceeding and including an action or suit brought by or in the right of the corporation, to the full extent permitted by any applicable portion of this Article Seven that shall not have been invalidated by any other applicable law. Section 12: Agreements. Upon, and in the event of, a determination of the Board to do so, the corporation is authorized to enter into indemnification agreements with some or all of its Directors, officers, employees and other agents providing for indemnification to the fullest extent permissible under California law and the corporation's Articles of Incorporation. Section 13: Retroactive Appeal. In the event this Article Seven is repealed or modified so as to reduce the protection afforded herein, the indemnification provided by this Article shall remain in full force and effect with respect to any act or omission occurring prior to such repeal or modification. ARTICLE EIGHT Obligations All obligations of the corporation, including promissory notes, checks, drafts, bills of exchange, and contracts of every kind, and evidences of indebtedness issued in the name of, or payable to, or executed on behalf of the corporation, shall be signed or endorsed by such officer or officers, or agent or agents, of the corporation and in such manner as, from time to time, shall be determined by the Board. ARTICLE NINE Corporate Seal The corporate seal shall set forth the name of the corporation, state, and date of incorporation. ARTICLE TEN Amendments These bylaws may be adopted, amended, or repealed by the vote of Shareholders entitled to exercise a majority of the voting power of the corporation or by the written assent of such Shareholders. Subject to such right of Shareholders, these bylaws, other than a bylaw or amendment thereof changing the authorized number of Directors, may be adopted, amended or repealed by the Board. ARTICLE ELEVEN Availability of Bylaws A current copy of these bylaws shall be mailed or otherwise furnished to any Shareholder of record within five days after receipt of a request therefor. SDG&E Bylaws - 10 - EBlawsSDG.doc

MASTER SERVICES CONTRACT Exhibit 10.61 SCHEDULE J TRANSACTION BASED STORAGE SERVICE AGREEMENT THIS TRANSACTION BASED STORAGE SERVICE AGREEMENT ("Agreement") is entered into as of the 4th day of November, 1998, by and between Southern California Gas Company ("Utility") and San Diego Gas & Electric Company ("Service User") and sets forth the terms and conditions under which Utility will provide storage services to Service User. This Agreement shall be attached to and incorporated as Schedule J to the Master Services Contract ("MSC") entered into by the parties. SECTION 1 - STORAGE SERVICES (a) For the Time Period for Service indicated below (the "Service Period"), Utility shall provide Service User with the storage services set forth below. This Agreement and the rights established herein shall be subject to the terms and conditions of Utility's Tariff Rate Schedule G-TBS and other applicable Tariff Rules hereto from time to time (including, without limitation, the definitions in Utility's Tariff Rule No. 1). Storage Maximum Firm or Time Period for Service Services Quantity As-Available ("Service Period") Inventory 6,000,000 (Dth) Firm, 4/1/99 to 3/31/00 Injection 28,037 (Dth/day) Firm 4/1/99 to 10/31/99 Withdrawal 225,000, (Dth/day) Firm 11/1/99 to 3/31/00 (b) All gas to be stored under this Agreement must be delivered by Service User to Utility system at the California border during the period from April 1, 1999 to March 31, 2000, subject, however, to Utility system constraints. Withdrawals must be completed by March 31, 1999 . (c) If storage injection and withdrawal services are offered hereunder on an "as-available" basis, such services may be temporarily restricted in accordance with Utility Tariff Rule 23.C.1.(4), Utility Tariff Rule 30.F.2 and G, and G-IMB Special Conditions 3. (d) Upon Service User's request for withdrawal, Utility will re- deliver all gas stored by Service User under this Agreement at the California border or other mutually agreed upon locations. (e) Other: Service User has multiple cycling rights. SECTION 2 - RESERVATION AND STORAGE CHARGES Service User agrees to pay to Utility the following charges: Variable Storage Charges Storage Quantity Unit Reservation In-Kind O&M Injection Services (Dth) Charges Fuel or Withdrawal Inventory 6,000,000 (Dth) 0.21 $/(Dth) Injection 28,037 (Dth/day) 0.10554 $/(Dth) 2.44% 0.0302$/(Dth) Withdrawal 225,000 (Dth/day) 13.306, $/(Dth/day) 0.0235$/(Dth) Other charges: The inventory, injection, and withdrawal reservation charges are adjusted effective April 1, 1999 with their percentage change equal to the percentage change of the Coinsumer Price Index - All Urban Consumbers ("CPI") for September as published by the Bureau of Labor Statistics of the United States Department of Labor in December. The percentage change is detemined by subtracting the previous Septmeber CPI from the latest September CPI and dividing the result by the previous September CPI. Injection variable charges (in-kind and O&M) apply april through November. Withdrawal variable chargesm (O&M) apply November through March. Variable charges are set by the G-TBS tariff. SECTION 3 - TRANSMISSION CHARGES Service User agrees to pay Utility all applicable transportation charges incurred to move gas to Utility system, including the Wheeler Ridge access fee, if applicable. Other transportation charges and conditions: All gas delivered for injection (less in-kind fuel) shall be assessed a transmission charge of $0.567 per deatherm and all gas withdrawn shall receive a credit of $0.567 per decatherm. The transmission charge and credit shall also apply to gas injected or withdrawn through imbalance trading or through a transfer with another storage account. SECTION 4 - BILLING AND PAYMENT (a) All reservation charges shall be billed by Utility and paid by Service User in equal monthly installments over the Service Period of this Agreement. Provided, however, that if Service User is not an end-use customer of Utility, 25% of the reservation charges shall be paid to Utility prior to the commencement of the Service Period and the balance shall be billed and paid in equal monthly installments over the Service Period. All other charges shall be billed and paid as the applicable services are provided. (b) All bills shall be timely paid. In addition to any remedies provided under Utility's Tariff Rate Schedules and Tariff Rules, in the event that Service User fails to timely pay any amounts due hereunder and such amounts are not paid in full within seven (7) days following notice by Utility that such payment is in arrears, Utility may, without any additional notice, immediately suspend service hereunder until Service User pays all amounts due. (c) In the event of a billing dispute, the bill must be paid in full by Service User pending resolution of the dispute. Such payment shall not be deemed a waiver of Service User's right to a refund. All bills shall be sent to Service User as specified below in Section 5 (a). SECTION 5 - MISCELLANEOUS (a) Notices - All notices and requests under this Agreement shall be deemed to have been duly given if sent by facsimile (fax) properly addressed, as with confirming original copy thereof being sent by postage prepaid, certified mail properly addressed, as following: SERVICE USER UTILITY Operating Matters Contact Name: Contact Name: Lonnie Mansi Gas Transactions Hotline Contact Title: Contact Title: Natural Gas Scheduler Gas Transactions & Operations Fax No.: (619) 650-6169 Fax No.: (213) 244-3900 Telephone: (619) 650-6192 Telephone: (213) 244-8281 Billing Matters Contact Name: Contact Name:, Mike G. Strong Susana Santa Maria Contact Title: Contact Title: Manger, Entergy Restructuring Billing Analyst & Entergy Accounting Fax No.: (619) 650-6170 Fax No.: (213) 244-4337 Telephone: (619) 650-6192 Telephone: (213) 244-8449 Contract Matters Contact Name: Contact Name: Carl Funke Gwoon Tom Contact Title: Contact Title: Sr. Energy Administrator Storage Products Manager Fax No.: (619) 650-6170 Fax No.: (213) 244-3692 Telephone: (619) 650-6192 Telephone: (213) 244-8645 Either party may change its designation set forth above by giving the other party at least seven (7) days prior written notice. (b) Governing Law - This Agreement shall be construed in accordance with the laws of the State of California and the orders, rules and regulations of the Public Utilities Commission of the State of California in effect from time to time. (c) Credit Worthiness - From time to time, as is deemed necessary, Utility may request that Service User furnish Utility with all relevant information or data to establish Service User's credit worthiness, including, without limitation, financial statements of Service User which are audited or otherwise attested to Utility's satisfaction. Following review of such information, Utility may require that Service User supply additional assurance as may be necessary to establish Service User's ongoing financial ability to perform under this Agreement during the Term, including, without limitation, contractual guarantees or financial instruments such as letters of credit. (d) Limited Storage Liability - Utility shall not be responsible for any loss of gas in storage, including, without limitation, losses due to the inherent qualities of gas (including leakage and migration) or due to physical or legal inability to withdraw gas from storage, unless such loss is caused by failure of Utility to exercise the ordinary care and diligence required by law. In the event of any such loss, the portion of such loss which is attributable to Service User shall be determined based on Service User's pro rata share of the total recoverable working gas inventory in Utility's storage facilities at the time of the loss. (e) Incorporated Provisions - The provisions of Section 6 of the MSC are incorporated by reference herein as if set forth in full herein, except to the extent such Section 6 is superseded by Utility's Tariff Rule 4. IN WITNESS WHEREOF, the authorized representatives of the parties have executed two (2) duplicate original copies of this Agreement as of the date first written above. SAN DIEGO GAS & ELECTRIC SOUTHERN CALIFORNIA GAS COMPANY By By Title: Title:

MASTER SERVICES CONTRACT Exhibit 10.62 SCHEDULE J TRANSACTION BASED STORAGE SERVICE AGREEMENT THIS TRANSACTION BASED STORAGE SERVICE AGREEMENT ("Agreement") is entered into as of the 4th day of February, 1998, by and between Southern California Gas Company ("Utility") and San Diego Gas & Electric Company ("Service User") and sets forth the terms and conditions under which Utility will provide storage services to Service User. This Agreement shall be attached to and incorporated as Schedule J to the Master Services Contract ("MSC") entered into by the parties. SECTION 1 - STORAGE SERVICES (a) For the Time Period for Service indicated below (the "Service Period"), Utility shall provide Service User with the storage services set forth below. This Agreement and the rights established herein shall be subject to the terms and conditions of Utility's Tariff Rate Schedule G-TBS and other applicable Tariff Rules hereto from time to time (including, without limitation, the definitions in Utility's Tariff Rule No. 1). Storage Maximum Firm or Time Period for Service Services Quantity As-Available ("Service Period") Inventory 6,000,000 (Dth) Firm, 4/1/98 to 3/31/99 Injection 28,037 (Dth/day) Firm 4/1/98 to 10/31/98 Withdrawal 225,000, (Dth/day) Firm 11/1/99 to 3/31/99 (b) All gas to be stored under this Agreement must be delivered by Service User to Utility system at the California border during the period from April 1, 1998 to October 31, 1998, subject, however, to Utility system constraints. Withdrawals must be completed by March 31, 1999 . (c) If storage injection and withdrawal services are offered hereunder on an "as-available" basis, such services may be temporarily restricted in accordance with Utility Tariff Rule 23.C.1.(4), Utility Tariff Rule 30.F.2 and G, and G-IMB Special Conditions 3. (d) Upon Service User's request for withdrawal, Utility will re- deliver all gas stored by Service User under this Agreement at the California border or other mutually agreed upon locations. (e) Other: Injection variable charges are applicable from April through November. Withdrawal variable charges are applicable from November through March. SECTION 2 - RESERVATION AND STORAGE CHARGES Service User agrees to pay to Utility the following charges: Variable Storage Charges Storage Quantity Unit Reservation In-Kind O&M Injection Services (Dth) Charges Fuel or Withdrawal Inventory 6,000,000 (Dth) 0.21 $/(Dth) Injection 28,037 (Dth/day) 0.10554 $/(Dth) 2.44% 0.0302$/(Dth) Withdrawal 225,000 (Dth/day) 13.306, $/(Dth/day) 0.0235$/(Dth) Other charges: N/A. SECTION 3 - TRANSMISSION CHARGES Service User agrees to pay Utility all applicable transportation charges incurred to move gas to Utility system, including the Wheeler Ridge access fee, if applicable. Other transportation charges and conditions: N/A. SECTION 4 - BILLING AND PAYMENT (a) All reservation charges shall be billed by Utility and paid by Service User in equal monthly installments over the Service Period of this Agreement. Provided, however, that if Service User is not an end-use customer of Utility, 25% of the reservation charges shall be paid to Utility prior to the commencement of the Service Period and the balance shall be billed and paid in equal monthly installments over the Service Period. All other charges shall be billed and paid as the applicable services are provided. (b) All bills shall be timely paid. In addition to any remedies provided under Utility's Tariff Rate Schedules and Tariff Rules, in the event that Service User fails to timely pay any amounts due hereunder and such amounts are not paid in full within seven (7) days following notice by Utility that such payment is in arrears, Utility may, without any additional notice, immediately suspend service hereunder until Service User pays all amounts due. (c) In the event of a billing dispute, the bill must be paid in full by Service User pending resolution of the dispute. Such payment shall not be deemed a waiver of Service User's right to a refund. All bills shall be sent to Service User as specified below in Section 5 (a). SECTION 5 - MISCELLANEOUS (a) Notices - All notices and requests under this Agreement shall be deemed to have been duly given if sent by facsimile (fax) properly addressed, as with confirming original copy thereof being sent by postage prepaid, certified mail properly addressed, as following: SERVICE USER UTILITY Operating Matters Contact Name: Contact Name: Roy Alvarez Gas Transactions Hotline Contact Title: Contact Title: Natural Gas Scheduler Gas Transactions & Operations Fax No.: (619) 696-1838 Fax No.: (213) 244-3900 Telephone: (619) 696-4455 Telephone: (213) 244-8281 Billing Matters Contact Name: Contact Name:, Hank Harris Susana Santa Maria Contact Title: Contact Title: Energy Support Services Supv. Billing Analyst Fax No.: (619) 696-4877 Fax No.: (213) 244-4337 Telephone: (619) 696-4433 Telephone: (213) 244-8449 Contract Matters Contact Name: Contact Name: Larry Hastings Gwoon Tom Contact Title: Contact Title: Sr. Energy Administrator Storage Products Manager Fax No.: (619) 696-2055 Fax No.: (213) 244-3692 Telephone: (619) 696-1869 Telephone: (213) 244-8645 Either party may change its designation set forth above by giving the other party at least seven (7) days prior written notice. (b) Governing Law - This Agreement shall be construed in accordance with the laws of the State of California and the orders, rules and regulations of the Public Utilities Commission of the State of California in effect from time to time. (c) Credit Worthiness - From time to time, as is deemed necessary, Utility may request that Service User furnish Utility with all relevant information or data to establish Service User's credit worthiness, including, without limitation, financial statements of Service User which are audited or otherwise attested to Utility's satisfaction. Following review of such information, Utility may require that Service User supply additional assurance as may be necessary to establish Service User's ongoing financial ability to perform under this Agreement during the Term, including, without limitation, contractual guarantees or financial instruments such as letters of credit. (d) Limited Storage Liability - Utility shall not be responsible for any loss of gas in storage, including, without limitation, losses due to the inherent qualities of gas (including leakage and migration) or due to physical or legal inability to withdraw gas from storage, unless such loss is caused by failure of Utility to exercise the ordinary care and diligence required by law. In the event of any such loss, the portion of such loss which is attributable to Service User shall be determined based on Service User's pro rata share of the total recoverable working gas inventory in Utility's storage facilities at the time of the loss. (e) Incorporated Provisions - The provisions of Section 6 of the MSC are incorporated by reference herein as if set forth in full herein, except to the extent such Section 6 is superseded by Utility's Tariff Rule 4. IN WITNESS WHEREOF, the authorized representatives of the parties have executed two (2) duplicate original copies of this Agreement as of the date first written above. SAN DIEGO GAS & ELECTRIC SOUTHERN CALIFORNIA GAS COMPANY By By Title: Title:

PRO FORMA EXHIBIT 10.63 MASTER SERVICES CONTRACT ACCOUNT NO. 18-8888-000-664-1 TAXPAYER I.D. (S) ORDER CONTROL CODE(S) SO5C This Contract is entered into by and between Southern California Gas Company ("Utility")and SAN DIEGO GAS & ~BLECTRIC ("Customer") as of the 30th day of JUNE, 1998. NOW THEREFORE, in consideration of the promises and mutual undertakings set forth herein, the parties agree as follows: Section 1 - Scope This Contract sets forth the general terms and conditions under which Utility will provide gas services to Customer pursuant to the applicable Tariff Rate Schedules and Tariff Rules which have been filed with the Public Utilities Commission of the State of California ("CPUC"), as in effect from time to time. Such services shall be limited to those services specified by Customer from time to time under Section 2 hereof and for which Customer qualifies. Service under this Contract shall commence on JULY 1st, 1998 ("Effective Date") and continue thereafter so tong as one or more of the attached Schedules referenced in Section 2 remain in effect. This Contract shall also remain in effect to permit any "winding up" occurring thereafter (e.g., billing and payment reconciliations, correction of gas imbalances, etc.) or to enforce or satisfy any obligations arising prior to the end of the Contract. Section 2 - Applicable Services Utility offers the following "menu" of gas services: A. Intrastate Transportation Service. (x) B. Marketer/Core Aggregator/Use or Pay Aggregator Service. ( ) C. GasSelect Service. ( ) D. Basic Storage Service. ( ) E. Auction Storage Service. ( ) F. Long Term Storage Service. ( ) G. Gas Swap Storage Service. ( ) H. Extended Balancing Storage Service. ( ) I. Other Services: ( ) Form 6597 - Revised 6/22/93 Contract # Customer has as of the Effective Date requested and agreed to pay for those services checked above. Utility has determined that Customer qualifies for such service(s). Additional services my be requested by Customer from time to time consistent with Utitity's Tariff Rate Schedules and Tariff Rules and any publicly-announced bidding, offering or operating procedures of Utility, and this Contract may be supplemented as appropriate. The agreement(s) specifying the terms and conditions for any or all of the above services requested by Customer shall be attached to the Contract as a "Schedule" (and incorporated herein by reference) using the alphabetical designation provided above. To the extent a particular service is not selected initially (or if terminated subsequently), a Schedule shall be attached stating that such service is "not applicable." To the extent that for any reason Customer desires to obtain the above services on a facility-by-facility basis, separate agreements shall be attached as separate Schedules and designated, e.g., "Schedule A-1," "Schedule A-2," etc., depending on the service applicable. Although the various services are compiled under this Contract for administration and other considerations, each service provided by Utility to Customer is separate and independent from all other services. Thus, the breach of the agreement for one service under a Schedule attached hereto shall not result in the breach of, or excuse performance under, another agreement for another service attached as a Schedule to this Contract. Likewise, there shall be no offset between any amounts claimed to be payable or due under one Schedule against amounts claimed to be payable or due under another Schedule. Section 3 - Interpretation In the event of any conflict between the provisions of this Contract and the provisions of any Schedule, the provisions of such Schedule shall be deemed to control; provided, however, notwithstanding the foregoing, this Contract and the Schedules attached hereto shall at all times be subject to (a) Utility's Tariff Rate Schedules and Tariff Rules, (b) all rules, regulations, decisions and orders of the CPUC, and ~(c) all other governmental laws, regulations, and decisions (including by a court) applicable to this Contract and/or the Schedules attached hereto, as each of the foregoing my be in effect from time to time. Section 4- Billing Payments All bills rendered by Utility shall be paid by Customer within nineteen (19) days after the billing date to Utitity's depository specified below (which may be changed by Utility on ten (10) days prior written notice). One master billing may be made by Utility for all services provided under this contract (including all Schedules attached hereto) after 1993 as mutually agreed. Such billing shall be sent to Customer at the following location: SAN DIEGO GAS & ELECTRIC P.O. BOX 1831 SAN DIEGO, CA 92112-4150 Attn : ACCOUNTING SUPERVISOR Additional copies of billings shall also be sent to the following facility location(s) of Customer: SAN DIEGO GAS & ELECTRIC P.O. BOX 1831 SAN DIEGO, CA 92112-4150 Attn Fuel Supervisor The parties recognize that billings may be subject to adjustment in subsequent periods during the term hereof or after the expiration of this Contract (or any Schedule) to reflect subsequent reconciliations with the records of interstate transporters or third parties delivering gas in California for Customer. All payments by Customer shall be made for the account of Utility to the following address: Southern California Gas Company P.O. BOX C MONTEREY PARK, CA 91756 Form 6597 - Revised 6/22/93 2 Contract Section 5 - Notices/Information All notices, requests or demands by either party shall be given in writing as specified in the effective Schedules attached hereto except that notices of changes to Section 4 shall be sent to the Master Billing Address of Customer for changes in Utility's depository and to Utility at the address provided below for changes in the Master Billing Address: Southern California Gas Company P.O. BOX 3249 LOS ANGELES, CA 90051-1249 Attn : Ms. Gwen R. Marelli, Wholesale Mkt Sales Mgr. Section 6 - Legal Provisions (A) Interpretation - The interpretation and performance of any contracts for gas service shall be in accordance with the laws of the State of California, and the orders, rules and regulations of the Public Utilities Commission of the State of California, in effect from time to time. (B) Amendment or Modification - Except as required to conform with California law and the orders, rules and regulations of the Public Utilities Commission of the State of California (which retains continuing jurisdiction over this Contract and the Schedules attached hereto), no amendment or modification shall be made to this Contract except by an instrument in writing executed by all parties thereto, and no amendment or modification shall be made by course of performance, course of dealing or usage of trade. (C) Waiver - No waiver by any party of one or more defaults under this Contract shall operate or be construed as a waiver of any other default or defaults, whether of a like or different character. (D) Damages - No party under this Contract shall be assessed any special, punitive, consequential, incidental, or indirect damages, whether in contract or tort, for any actions or inactions arising from or related to this Contract. (E) Assignment - This Contract (or any rights or obligations related thereto) shall not be assigned without the prior written consent of Utility, which consent shall not be withheld unreasonably (but Utility may require that any assignee confirm in writing its assumption of the rights and obligations of its predecessor). (F) Hinshaw Exemption - In the event that any governmental entity (including a court) issues an order or rule which would result in the loss of Utitity's Hinshaw Exemption from Federal regulations if this Contract entered into by Utility remains in effect, Utility may terminate this Contract. The foregoing provisions (A) through (F) shall be superseded to the extent such matters are covered by Utitity's Tariff Rule 4, as in effect from time to time. IN WITNESS WHEREOF, the authorized representatives of the parties have executed this Contract in two (2) duplicate original copies. SAN DIEGO GAS & ELECTRIC SOUTHERN CALIFORNIA GAS COMPANY By By Ms. Gwen R. Marelli Title: Sr. Vice President-Energy Title: Wholesale Mkt Sales Mgr. Supply Exhibit 10.63 Form 6597 - Revised 2/11/93 3 Contract # MASTER SERVICES CONTRACT SCHEDULE A INTRASTATE TRANSMISSION SERVICE ACCOUNT NUMBER 18-8888-000-664-1 This Agreement is entered into by and between Southern California Gas Company ("Utility")and SAN DIEGO GAS & ELECTRIC ("Customer") as of the 30th day of JUNE, 1998 . This Agreement shall be attached to and incorporated as a Schedule in the Master Services Contract ("MSC") executed by the Parties. NOW THEREFORE, in consideration of the promises and mutual undertakings set forth herein, the parties agree as follows: Section I - Scope A. Intent This Agreement sets forth the general terms and conditions under which Utility will transport gas, or transport and procure gas, for customer in California pursuant to Utility's applicable Tariff Rate Schedules and Tariff Rules ("Tariffs") on file with Public Utilities Commission of the State of California ("CPUC"), as each are in effect from time to time. To the extent not inconsistent herewith, the provisions of ~MSC are incorporated by reference in this agreement. All transmission services by Utility shall be paid for by Customer at the rates specified in the applicable Tariffs, except as otherwise specified herein. Nothing in this Agreement shall be construed as preventing Utility and Customer from mutually agreeing to conditions which are more stringent than set forth in the Tariffs. B. Effective Date/Term (1) The Effective Date of this Agreement shall be as of 6:00 AM on JULY 1st, 1998. (2) The initial term of this Agreement shall end on JULY 1st, 2000. At the end of the initial term, this Agreement shall continue thereafter on a month to month basis unless terminated by written notice from one party to the other given not less than twenty (20) days prior to the last day of the initial term of any month thereafter. Section 2 - Services Provided and Redelivery Locations Customer has requested and agreed to pay for, and Utility has determined that Customer is qualified for transmission services to the following locations (the data provided will be utilized by Utility in determinations regarding curtailment) and any special sequencing of redelivery conditions should be noted in Section 9(E): Form 6597-1 - original 1/12/93 Contract # Facility A Facility Name: SAN DIEGO GAS % ELECTRIC Account Number: 18-8888-000-664-1 Address: SIC Code: 4939 Combination utilities, nec Mail copy of Bill to this Facility: NO Supplemental Facility Account Number(s): N/A Full Requirements YES (Noncore only) Facility Customer Contacts Operations Emergency Name: Operations Control Name: Scott Ferguson Title : Supervisor Title : Director, Gas Department Address: 3494 E. PICO BLVD. Address: P.O. BOX 1831 LOS ANGELES, CA 90023-3003 SAN DIEGO, CA 92112-4150 Tel. No: 323/266-5938 Tel. No: (619) 549-6503 Fax No : 323/269-5345 Fax No: (619) 549-6522 Customer shall notify Utility in the event of any change in the gas requirements or notification designations for this facility. If Customer receives its full requirements under Core Subscription in the event during any month Customer utilizes gas in excess of the following monthly scheduled quantity, such usage shall be treated as reserved capacity for the entire year. Form 6597-1 - Original 1/12/93 - 2 - Contract # 92820 Sequence 01 Billing Schedule Otherwise Rate Net Transmission Rates Applicable Schedule Priority Billed Tariff/Negotiated Rate GT-F11 FIRM N/A -TARIFF- Term: 2 YEARS Monthly Scheduled Quantity (Therms) Jan 31,570,000 Jul 54,080,000 Feb 26,925,000 Aug 52,070,000 Mar 34,813,000 Sep 60,410,000 Apr 40,879,000 Oct 36,080,000 May 52,234,000 Nov 29,310,000 Jun 44,787,000 Dec 30,420,000 Annual Quantity 493,578,000 Use or Pay Aggregator NO (Only applies to firm rates under partial requirements) Customer's regular days for operations under this sequence are: M (X) T (X) W (X) Th (X) F (X) Sat (X) Sun (X) Form 6597-1 - Original 1/12/93 - 3 - Contract # Section 3 - Other Existing Transportation/Exchange Arrangements (1) Customer has existing intrastate transportation/exchange arrangements with Utility: (2) Date of Arrangement: (3) Term of Arrangement: (4) This Agreement shall have no impact on such existing arrangement except: Section 4 - Transportation Delivery Options Customers "Order Control Code" (OCC) for gas transportation by Utility is : SO5C. A. Transportation Delivery Points Gas may be delivered to Utility for transportation for Customer's account at the following interconnection delivery points on Utility's pipeline facilities. Gaviota Gas Plant Intertie with SoCalGas near outlet of the Chevron onshore treating facility South Coles Levee Intertie with SoCalGas at point near the outlet of the South Coles Levee Plant 3p Gasoline Extraction Plant Intertie with SoCalGas at Kettleman Hills PG and E Intertie with SoCalGas at Kern River Station El Paso Natural Gas Intertie with SoCalGas at Topock PG and E Intertie with SoCalGas at Kettleman PG and E Intertie with SoCalGas at Elk Hills PG and E Intertie with SoCalGas at Topock El Paso Natural Gas Intertie with SoCalGas at Blythe PG and E Intertie with SoCalGas at Elk Pisgah Transwestern Intertie with SoCalGas at Needles Carpenteria Gas Plant Intertie with SoCalGas and junction of Carpenteria Ave. and U.S. Hwy 101 Kern/Mojave Intertie with SoCalGas at Wheeler Ridge Priority of access to any Delivery Point shall be as set forth in the Tariffs or as otherwise established by the CPUC. B. Operations All nominations, confirmations, and other operating procedures for transportation services shall be subject to the rules and conditions established therefor by Utility. Customer shall be responsible for obtaining, and subject to any liability or loss regarding, any upstream transportation prior to the receipt of gas by Utility for Customer's account, except for core and core- subscription usage. Customer's failure to obtain firm upstream transportation rights to ensure delivery to Utility shall not be deemed to be a condition of Force Majeure. Any deviations from a standard 5 or 7 day week should be noted in Section 9(E). Section 5 - Service Interruption Credit The firm transportation services by Utility under this Agreement may be subject to the applicable "Service Interruption Credit" as set forth in Utility's Tariffs. Section 6 - Billing and Payment Billing and Payment for services hereunder shall be as provided in Utility's applicable Tariffs, with payment due from Customer to Utility not later than 19 days following the date of Utility's invoice. Any special billing instructions should be noted in Section 9(E). Form 6597-1 - Original 1/12/93 - 4 - Contract # 92820 Section 7 - Imbalances Utility shall provide Customer with an imbalance service in connection with transportation of gas hereunder pursuant to Tariff Rate Schedule G-IMB, as in effect from time to time (or any successor thereto). Any applicable imbalance charges shall be charged to Account Number: For any Customer utilizing the services of a Contracted Marketer, a summary of transactional activities shall be provided to the following designated account: N/A. Section 8 - Transfer of Rights Subject to Section 9(A), this Agreement and the rights and obligations hereunder shall only be transferred or assigned with the prior written consent of Utility which shall not be withheld unreasonably, provided that any successor first established its "creditworthiness" and assumes such contractual rights and obligations in writing. Section 9 - Miscellaneous A. Representatives - Customer shall utilize the services of: (1) Contracted Marketer : N/A Authorized to access Customer's meter usage: N/A Will nominate on Customer's behalf: N/A Will trade on Customer's behalf: N/A (2) Agent : N/A Authorized to access Customer's meter usage: N/A Will nominate on Customer's behalf: N/A Will trade on Customer's behalf: N/A (3) Use or Pay Aggregator: N/A Aggregators will automatically be authorized to access Customer's meter usage. To the extent applicable, appropriate authorization by Customer (including the the terms and conditions thereof) have been attached to MSC and are incorporated by reference (as supplemented from time to time) in this Agreement. If Customer designates a Marketer or Agent, any communications made by such Marketer/Agent shall be binding on Customer and shall prevail in any conflict during the period such authorization remains in effect. Such authorization shall remain in effect for the term of this Agreement unless otherwise specified in the initial authorization, or unless terminated pursuant to notification received written by the Utility. In order for a Marketer/Agent to nominate on Customer's behalf, such designated Marketer/Agent must be so designated by the 20th of month preceding any particular nomination. Form 6597-1 - Original 1/12/93 - 5 - Contract # B. Contacts/Notices: All day to day contacts with Customer shall be as specified for each Facility above. Operating contacts to be used by customer with Utility shall be: Operations/Emergency Customer Service Contact Title: Contact Title: Gas Transactions Manager Wholesale Mkt Sales Mgr. Telephone No: (213) 244-3900 Telephone No: (213) 244-3701 Fax No: N/A Fax No: (213) 244-8222 Any written notices from one party to the other affecting this Agreement shall be sent to the following locations (unless changed by seven days prior written notice): Customer Utility SAN DIEGO GAS & ELECTRIC Southern California Gas Company P.O. BOX 1831 P.O. BOX 3249 SAN DIEGO, CA 92112 LOS ANGELES, CA 90051-1249 Attn: Attn: MS. Gwen R. Marelli Title: Fuel Supervisor Title: Wholesale Mkt Sales Mgr. C. Definitions: All definitions set forth in the Tariffs, including without Limitation Utility Rule 1, are incorporated herein by reference as if set forth in full. D. Miscellaneous Legal Provisions: The miscellaneous legal provisions in Section 6 of the MSC are incorporated by reference herein as if set forth in full, except to the extent such Section 6 is superseded by Utitity's Tariff Rule 4. E. Special Conditions : The following special conditions of service are applicable hereto: This Contract includes account numbers 18-3501-001-951-1 (meter #8861), 18-3501-001-950-1 (meter #1143), 18-8334-455-952-1 (meter #8862), and 18-8339-190-603-1 (meter #4024925). IN WITNESS WHEREOF, the authorized representatives of the parties have executed two duplicate original copies hereof. Customer Utility Name : Name: SAN DIEGO GAS & ELECTRIC Southern California Gas Company By: By: Ms. Gwen R. Marelli Title : Title: Sr. Vice President-Energy Supply Wholesale Mkt Sales Mgr. Form 6597-1 - original 1/12/93 - 6 - Contract #

Exhibit 10.64 MASTER SERVICES CONTRACT ACCOUNT NO. 18-3501-001-951-1 TAXPAYER I.D. (S) ORDER CONTROL CODE(S) SO5, SO5A This Contract is entered into by and between Southern California Gas Company ("Utility")and SAN DIEGO GAS & ELECTRIC ("Customer") as of the 30th day of JUNE, 1998. NOW THEREFORE, in consideration of the promises and mutual undertakings set forth herein, the parties agree as follows: Section 1 - Scope This Contract sets forth the general terms and conditions under which Utility will provide gas services to Customer pursuant to the applicable Tariff Rate Schedules and Tariff Rules which have been filed with the Public Utilities Commission of the State of California ("CPUC"), as in effect from time to time. Such services shall be limited to those services specified by Customer from tire to time under Section 2 hereof and for which Customer qualifies. Service under this Contract shall commence on JULY 1st, 1998 ("Effective Date") and continue thereafter so long as one or more of the attached Schedules referenced in Section 2 remain in effect. This Contract shall also remain in effect to permit any "winding up" occurring thereafter (e.g., billing and payment reconciliations, collection of gas imbalances, etc.) or to enforce or satisfy any obligations arising prior to the end of the Contract. Section 2 - Applicable Utility offers the following "menu" of gas services: A. Intrastate Transportation Service. (x) B. Marketer/Core Aggregator/Use or Pay Aggregator Service. ( ) C. GasSelect Service. (x) D. Basic Storage Service. ( ) E. Auction Storage Service. ( ) F. Long Term Storage Service. ( ) G. Gas Swap Storage Service. ( ) M. Extended Balancing Storage Service. ( ) l. Other Services: (x) <7/7/98> <7/8/98> Form 6597 - Revised 6/22/93 Contract # Customer has as of the Effective Date requested and agreed to pay for those services checked above. Utility has determined that Customer qualifies for such service(s). Additional services my be requested by Customer from time to time consistent with Utitity's Tariff Rate Schedules and Tariff Rules and any publicly-announced bidding, offering or operating procedures of Utility, and this Contract may be supplemented as appropriate. The agreement(s) specifying the terms and conditions for any or all of the above services requested by Customer shall be attached to the Contract as a "Schedule" (and incorporated herein by reference) using the alphabetical designation provided above. To the extent a particular service is not selected initially (or if terminated subsequently), a Schedule shall be attached stating that such service is "not applicable." To the extent that for any reason Customer desires to obtain the above services on a facility-by-facility basis, separate agreements shall be attached as separate Schedules and designated, e.g., "Schedule A-1," "Schedule A-2," etc., depending on the service applicable. Although the various services are compiled under this Contract for administration and other considerations, each service provided by Utility to Customer is separate and independent from all other services. Thus, the breach of the agreement for one service under a Schedule attached hereto shall not result in the breach of, or excuse performance under, another agreement for another service attached as a Schedule to this Contract. Likewise, there shall be no offset between any amounts claimed to be payable or due under one Schedule against amounts claimed to be payable or due under another Schedule. Section 3 - Interpretation In the event of any conflict between the provisions of this Contract and the provisions of any Schedule, the provisions of such Schedule shall be deemed to control; provided, however, notwithstanding the foregoing, this Contract and the Schedules attached hereto shall at all times be subject to (a) Utility's Tariff Rate Schedules and Tariff Rules, (b) all rules, regulations, decisions and orders of the CPUC, and ~(c) all other governmental laws, regulations, and decisions (including by a court) applicable to this Contract and/or the Schedules attached hereto, as each of the foregoing my be in effect from time to time. Section 4- Billing Payments All bills rendered by Utility shall be paid by Customer within nineteen (19) days after the billing date to Utitity's depository specified below (which may be changed by Utility on ten (10) days prior written notice). One master billing may be made by Utility for all services provided under this contract (including all Schedules attached hereto) after 1993 as mutually agreed. Such billing shall be sent to Customer at the following location: SAN DIEGO GAS & ELECTRIC P.O. BOX 1831 SAN DIEGO, CA 92112-4150 Attn : ACCOUNTING SUPERVISOR Additional copies of billings shall also be sent to the following facility location(s) of Customer: SAN DIEGO GAS & ELECTRIC P.O. BOX 1831 SAN DIEGO, CA 92112-4150 Attn Fuel Supervisor The parties recognize that billings may be subject to adjustment in subsequent periods during the term hereof or after the expiration of this Contract (or any Schedule) to reflect subsequent reconciliations with the records of interstate transporters or third parties delivering gas in California for Customer. All payments by Customer shall be made for the account of Utility to the following address: Southern California Gas Company P.O. BOX C MONTEREY PARK, CA 91756 Form 6597 - Revised 6/22/93 2 Contract Section 5 - Notices/Information All notices, requests or demands by either party shall be given in writing as specified in the effective Schedules attached hereto except that notices of changes to Section 4 shall be sent to the Master Billing Address of Customer for changes in Utility's depository and to Utility at the address provided below for changes in the Master Billing Address: Southern California Gas Company P.O. BOX 3249 LOS ANGELES, CA 90051-1249 Attn : Ms. Gwen R. Marelli, Wholesale Mkt Sales Mgr. Section 6 - Legal Provisions (A) Interpretation - The interpretation and performance of any contracts for gas service shall be in accordance with the laws of the State of California, and the orders, rules and regulations of the Public Utilities Commission of the State of California, in effect from time to time. (B) Amendment or Modification - Except as required to conform with California law and the orders, rules and regulations of the Public Utilities Commission of the State of California (which retains continuing jurisdiction over this Contract and the Schedules attached hereto), no amendment or modification shall be made to this Contract except by an instrument in writing executed by all parties thereto, and no amendment or modification shall be made by course of performance, course of dealing or usage of trade. (C) Waiver - No waiver by any party of one or more defaults under this Contract shall operate or be construed as a waiver of any other default or defaults, whether of a like or different character. (D) Damages - No party under this Contract shall be assessed any special, punitive, consequential, incidental, or indirect damages, whether in contract or tort, for any actions or inactions arising from or related to this Contract. (E) Assignment - This Contract (or any rights or obligations related thereto) shall not be assigned without the prior written consent of Utility, which consent shall not be withheld unreasonably (but Utility may require that any assignee confirm in writing its assumption of the rights and obligations of its predecessor). (F) Hinshaw Exemption - In the event that any governmental entity (including a court) issues an order or rule which would result in the loss of Utitity's Hinshaw Exemption from Federal regulations if this Contract entered into by Utility remains in effect, Utility may terminate this Contract. The foregoing provisions (A) through (F) shall be superseded to the extent such matters are covered by Utitity's Tariff Rule 4, as in effect from time to time. IN WITNESS WHEREOF, the authorized representatives of the parties have executed this Contract in two (2) duplicate original copies. SAN DIEGO GAS & ELECTRIC SOUTHERN CALIFORNIA GAS COMPANY By By Ms. Gwen R. Marelli Title: Sr. Vice President-Energy Title: Wholesale Mkt Sales Mgr. Supply Form 6597 - Revised 2/11/93 3 Contract # MASTER SERVICES CONTRACT SCHEDULE A INTRASTATE TRANSMISSION SERVICE ACCOUNT NUMBER 18-3501-001-951-1 This Agreement is entered into by and between Southern California Gas Company ("Utility")and SAN DIEGO GAS & ELECTRIC ("Customer") as of the 29th day of JUNE, 1998 . This Agreement shall be attached to and incorporated as a Schedule in the Master Services Contract ("MSC") executed by the Parties. NOW THEREFORE, in consideration of the promises and mutual undertakings set forth herein, the parties agree as follows: Section I - Scope A. Intent This Agreement sets forth the general terms and conditions under which Utility will transport gas, or transport and procure gas, for customer in California pursuant to Utility's applicable Tariff Rate Schedules and Tariff Rules ("Tariffs") on file with Public Utilities Commission of the State of California ("CPUC"), as each are in effect from time to time. To the extent not inconsistent herewith, the provisions of ~MSC are incorporated by reference in this agreement. All transmission services by Utility shall be paid for by Customer at the rates specified in the applicable Tariffs, except as otherwise specified herein. Nothing in this Agreement shall be construed as preventing Utility and Customer from mutually agreeing to conditions which are more stringent than set forth in the Tariffs. B. Effective Date/Term (1) The Effective Date of this Agreement shall be as of 6:00 AM on JULY 1st, 1998. (2) The initial term of this Agreement shall end on JULY 1st, 2000. At the end of the initial term, this Agreement shall continue thereafter on a month to month basis unless terminated by written notice from one party to the other given not less than twenty (20) days prior to the last day of the initial term of any month thereafter. Section 2 - Services Provided and Redelivery Locations Customer has requested and agreed to pay for, and Utility has determined that Customer is qualified for transmission services to the following locations (the data provided will be utilized by Utility in determinations regarding curtailment) and any special sequencing of redelivery conditions should be noted in Section 9(E): Form 6597-1 - original 1/12/93 Contract # 92820 Facility A Facility Name SAN DIEGO GAS % ELECTRIC Account Number 18-3501-001-951-1 Address 0001 RAINBOW STATION MORENO VALLEY, CA 92360 SIC Code 4939 Combination utilities, nec Mail copy of Bill to this Facility: NO Supplemental Facility Account Number(s): 18-3501-001-950-1 18-8334-455-952-1 18-8339-190-603-1 Full Requirements YES (Noncore only) Facility Customer Contacts Operations Emergency Name: Operations Control Name: Scott Ferguson Title : Supervisor Title : Director, Gas Department Address: 3494 E. PICO BLVD. Address: P.O. BOX 1831 LOS ANGELES, CA 90023-3003 SAN DIEGO, CA 92112 Tel. No: 323/266-5938 Tel. No: (619) 549-6503 Fax No : 323/269-5345 Fax No: (619) 549-6522 Customer shall notify Utility in the event of any change in the gas requirements or notification designations for this facility. If Customer receives its full requirements under Core Subscription in the event during any month Customer utilizes gas in excess of the following monthly scheduled quantity, such usage shall be treated as reserved capacity for the entire year. Form 6597-1 - Original 1/12/93 - 2 - Contract # 92820 Sequence 01 Billing Schedule Otherwise Rate Net Transmission Rates Applicable Schedule Priority Billed Tariff/Negotiated Rate GT-F8 FIRM N/A -TARIFF- Term: 2 YEARS Monthly Scheduled Quantity (Therms) Jan 85,340,000 Jul 48,443,000 Feb 73,683,000 Aug 46,589,000 Mar 63,310,000 Sep 44,675,000 Apr 56,822,000 Oct 50,716,000 May 49,998,000 Nov 60,286,000 Jun 46,523,000 Dec 90,338,000 Annual Quantity 716,723,000 Use or Pay Aggregator NO (Only applies to firm rates under partial requirements) Customer's regular days for operations under this sequence are: M (X) T (X) W (X) Th (X) F (X) Sat (X) Sun (X) Form 6597-1 - Original 1/12/93 - 3 - Contract # 92820 Section 3 - Other Existing Transportation/Exchange Arrangements (1) Customer has existing intrastate transportation/exchange arrangements with Utility: (2) Date of Arrangement: (3) Term of Arrangement: (4) This Agreement shall have no impact on such existing arrangement except: Section 4 - Transportation Delivery Options Customers "Order Control Code" (OCC) for gas transportation by Utility is : SO5. A. Transportation Delivery Points Gas may be delivered to Utility for transportation for Customer's account at the following interconnection delivery points on Utility's pipeline facilities. Gaviota Gas Plant Intertie with SoCalGas near outlet of the Chevron onshore treating facility South Coles Levee Intertie with SoCalGas at point near the outlet of the South Coles Levee Plant 3p Gasoline Extraction Plant Intertie with SoCalGas at Kettleman Hills PG and E Intertie with SoCalGas at Kern River Station El Paso Natural Gas Intertie with SoCalGas at Topock PG and E Intertie with SoCalGas at Kettleman PG and E Intertie with SoCalGas at Elk Hills PG and E Intertie with SoCalGas at Topock El Paso Natural Gas Intertie with SoCalGas at Blythe PG and E Intertie with SoCalGas at Elk Pisgah Transwestern Intertie with SoCalGas at Needles Carpenteria Gas Plant Intertie with SoCalGas and junction of Carpenteria Ave. and U.S. Hwy 101 Kern/Mojave Intertie with SoCalGas at Wheeler Ridge Priority of access to any Delivery Point shall be as set forth in the Tariffs or as otherwise established by the CPUC. B. Operations All nominations, confirmations, and other operating procedures for transportation services shall be subject to the rules and conditions established therefor by Utility. Customer shall be responsible for obtaining, and subject to any liability or loss regarding, any upstream transportation prior to the receipt of gas by Utility for Customer's account, except for core and core- subscription usage. Customer's failure to obtain firm upstream transportation rights to ensure delivery to Utility shall not be deemed to be a condition of Force Majeure. Any deviations from a standard 5 or 7 day week should be noted in Section 9(E). Section 5 - Service Interruption Credit The firm transportation services by Utility under this Agreement may be subject to the applicable "Service Interruption Credit" as set forth in Utility's Tariffs. Section 6 - Billing and Payment Billing and Payment for services hereunder shall be as provided in Utility's applicable Tariffs, with payment due from Customer to Utility not later than 19 days following the date of Utility's invoice. Any special billing instructions should be noted in Section 9(E). Form 6597-1 - Original 1/12/93 - 4 - Contract # 92820 Section 7 - Imbalances Utility shall provide Customer with an imbalance service in connection with transportation of gas hereunder pursuant to Tariff Rate Schedule G-IMB, as in effect from time to time (or any successor thereto). Any applicable imbalance charges shall be charged to Account Number: 18-3501-001-951-1. For any Customer utilizing the services of a Contracted Marketer, a summary of transactional activities shall be provided to the following designated account: N/A. Section 8 - Transfer of Rights Subject to Section 9(A), this Agreement and the rights and obligations hereunder shall only be transferred or assigned with the prior written consent of Utility which shall not be withheld unreasonably, provided that any successor first established its "creditworthiness" and assumes such contractual rights and obligations in writing. Section 9 - Miscellaneous A. Representatives - Customer shall utilize the services of: (1) Contracted Marketer : N/A Authorized to access Customer's meter usage: N/A Will nominate on Customer's behalf: N/A Will trade on Customer's behalf: N/A (2) Agent : N/A Authorized to access Customer's meter usage: N/A Will nominate on Customer's behalf: N/A Will trade on Customer's behalf: N/A (3) Use or Pay Aggregator: N/A Aggregators will automatically be authorized to access Customer's meter usage. To the extent applicable, appropriate authorization by Customer (including the the terms and conditions thereof) have been attached to MSC and are incorporated by reference (as supplemented from time to time) in this Agreement. If Customer designates a Marketer or Agent, any communications made by such Marketer/Agent shall be binding on Customer and shall prevail in any conflict during the period such authorization remains in effect. Such authorization shall remain in effect for the term of this Agreement unless otherwise specified in the initial authorization, or unless terminated pursuant to notification received written by the Utility. In order for a Marketer/Agent to nominate on Customer's behalf, such designated Marketer/Agent must be so designated by the 20th of month preceding any particular nomination. Form 6597-1 - Original 1/12/93 - 5 - Contract # 92820 B. Contacts/Notices: All day to day contacts with Customer shall be as specified for each Facility above. Operating contacts to be used by customer with Utility shall be: Operations/Emergency Customer Service Contact Title: Contact Title: Gas Transactions Manager Wholesale Mkt Sales Mgr. Telephone No: (213) 244-3900 Telephone No: (213) 244-3701 Fax No: N/A Fax No: (213) 244-8222 Any written notices from one party to the other affecting this Agreement shall be sent to the following locations (unless changed by seven days prior written notice): Customer Utility SAN DIEGO GAS & ELECTRIC Southern California Gas Company P.O. BOX 1831 P.O. BOX 3249 SAN DIEGO, CA 92112 LOS ANGELES, CA 90051-1249 Attn: Attn: MS. Gwen R. Marelli Title: Fuel Supervisor Title: Wholesale Mkt Sales Mgr. C. Definitions: All definitions set forth in the Tariffs, including without Limitation Utility Rule 1, are incorporated herein by reference as if set forth in full. D. Miscellaneous Legal Provisions: The miscellaneous legal provisions in Section 6 of the MSC are incorporated by reference herein as if set forth in full, except to the extent such Section 6 is superseded by Utitity's Tariff Rule 4. E. Special Conditions : The following special conditions of service are applicable hereto: In addition to OCC S05 in Section 4, OCC S05A also applies. IN WITNESS WHEREOF, the authorized representatives of the parties have executed two duplicate original copies hereof. Customer Utility Name : Name: SAN DIEGO GAS & ELECTRIC Southern California Gas Company By: By: Ms. Gwen R. Marelli Title : Title: Sr. Vice President-Energy Supply Wholesale Mkt Sales Mgr. Form 6597-1 - original 1/12/93 - 6 - Contract # 92820

EXHIBIT 12.1 SAN DIEGO GAS & ELECTRIC COMPANY COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS (Dollars in thousands) 1994 1995 1996 1997 1998* 1998** -------- -------- -------- -------- --------- ---------- Fixed Charges: Interest: Long-Term Debt $ 81,749 $ 82,591 $ 76,463 $ 69,546 $ 54,664 $ 54,664 Short-Term Debt 8,894 17,886 12,635 13,825 12,933 12,933 Rate Reduction Bonds -- -- -- -- -- 40,912 Amortization of Debt Discount and Expense, Less Premium 4,604 4,870 4,881 5,154 7,749 7,749 Interest Portion of Annual Rentals 9,496 9,631 8,446 9,496 8,250 8,250 -------- -------- -------- -------- --------- ---------- Total Fixed Charges 104,743 114,978 102,425 98,021 83,596 124,508 -------- -------- -------- -------- --------- ---------- Preferred Dividends Requirements 7,663 7,663 6,582 6,582 6,582 6,582 Ratio of Income Before Tax to Net Income 1.83501 1.78991 1.88864 1.91993 1.73993 1.73993 -------- -------- -------- -------- --------- ---------- Preferred Dividends for Purpose of Ratio 14,062 13,716 12,431 12,637 11,452 11,452 -------- -------- -------- -------- --------- ---------- Total Fixed Charges and Preferred Dividends for Purpose of Ratio $118,805 $128,694 $114,856 $110,658 $ 95,048 $135,960 ======== ======== ======== ======== ========= ========== Earnings: Net Income (before preferred dividend requirements) $206,296 $219,049 $222,765 $238,232 $191,204 $191,204 Add: Fixed Charges (from above) 104,743 114,978 102,425 98,021 83,596 124,508 Less: Fixed Charges Capitalized 1,424 2,040 1,495 2,052 846 846 Taxes on Income 172,259 173,029 197,958 219,156 141,477 141,477 -------- -------- -------- -------- --------- ---------- Total Earnings for Purpose of Ratio $481,874 $505,016 $521,653 $553,357 $415,431 $456,343 ======== ======== ======== ======== ========= ========== Ratio of Earnings to Combined Fixed Charges and Preferred Dividends 4.06 3.92 4.54 5.00 4.37 3.36 ======== ======== ======== ======== ========= ========== * Not including interest for rate reduction bonds. ** Including interest for rate reduction bonds.

EXHIBIT 23.01 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 33-45599, 33-52834, and 33-49837 of San Diego Gas & Electric Company on Forms S-3 of our report dated January 27, 1999, except for Note 14 as to which the date is February 22, 1999, appearing in this Annual Report on Form 10-K of San Diego Gas & Electric Company for the year ended December 31, 1998. /s/ DELOITTE & TOUCHE LLP San Diego, California March 31, 1999

UT THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONDENSED STATEMENT OF CONSOLIDATED INCOME, BALANCE SHEET AND CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0000086521 SAN DIEGO GAS & ELECTRIC COMPANY 1,000,000 YEAR DEC-31-1998 DEC-31-1998 PER-BOOK 2,300 498 696 756 7 4,257 291 566 267 1,124 25 78 1,491 0 0 0 66 0 57 6 1,410 4,257 2,749 133 2,330 2,463 286 21 307 116 191 6 185 319 96 535 0 0