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 - ------ ------- SEMPRA ENERGY - ------------------------------------------------------------------- (Exact name of registrant as specified in its charter) CALIFORNIA 1-14201 33-0732627 - ------------------------------------------------------------------- (State of incorporation (Commission (I.R.S. Employer or organization) File Number) Identification No.) 101 ASH STREET, SAN DIEGO, CALIFORNIA 92101 - ------------------------------------------------------------------- (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 - ------------------- --------------------- Common Stock, Without Par Value New York and Pacific 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 31. Glossary on page 43. Aggregate market value of the voting stock held by non-affiliates of the registrant as of January 31, 1999 was $5.6 billion. Registrant's common stock outstanding as of February 28, 1999 was 240,111,553 shares. DOCUMENTS INCORPORATED BY REFERENCE: Portions of the 1998 Annual Report to Shareholders are incorporated by reference into Parts I, II, and IV. Portions of the Proxy 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 . . . . . . . . . . . . . . . . . . . . . .21 Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . .21 Item 4. Submission of Matters to a Vote of Security Holders. .22 Executive Officers of the Registrant . . . . . . . . .22 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . . .22 Item 6. Selected Financial Data. . . . . . . . . . . . . . . .23 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . .23 Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . .23 Item 8. Financial Statements and Supplementary Data. . . . . .24 Item 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . .24 PART III Item 10. Directors and Executive Officers of the Registrant . .24 Item 11. Executive Compensation . . . . . . . . . . . . . . . .24 Item 12. Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . . .24 Item 13. Certain Relationships and Related Transactions . . . .24 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . . . . . . . . . .25 Independent Auditors' Consent and Report on Schedule. . . . . .27 Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . .30 Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . .31 Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . .43 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 A description of Sempra Energy and its subsidiaries (the Company) is given in "Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 1998 Annual Report to Shareholders, which is incorporated by reference. GOVERNMENT REGULATION Local Regulation Southern California Gas Company (SoCalGas) has gas franchises with the 236 legal jurisdictions in its service territory. These franchises allow SoCalGas to locate facilities for the transmission and distribution of natural gas in the streets and other public places. Most of the franchises do not have fixed terms and continue indefinitely. The range of expiration dates for the franchises with definite terms is 2003 to 2041. San Diego Gas and Electric (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 and SoCalGas' 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. SoCalGas obtains a number of permits, authorizations and licenses in connection with the transmission and distribution of natural gas. 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: Gas: Regular sales- Residential $ 2,234 $ 1,957 $ 1,809 Commercial/Industrial 571 617 573 Utility Generation 9 14 9 --------- --------- --------- 2,814 2,588 2,391 Transportation & Exchange- Residential 11 10 10 Commercial/Industrial 277 273 257 Utility Generation 66 76 70 Wholesale 7 12 10 --------- --------- ---------- 361 371 347 Balancing and Other (403) 5 (28) --------- --------- ---------- Total Gas Revenues 2,772 2,964 2,710 --------- --------- ---------- Electric: Residential 637 684 647 Commercial 643 680 625 Industrial 233 268 261 Balancing and Other 352 137 58 --------- --------- --------- Total Electric Revenues 1,865 1,769 1,591 --------- --------- --------- Total Utility Revenues $ 4,637 $ 4,733 $ 4,301 ========= ========= ========= Industry segment information is contained in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 15 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. NATURAL GAS OPERATIONS The Company purchases, sells, distributes, stores and transports natural gas. SDG&E purchases natural gas for resale to its customers in San Diego and southern Orange counties, and as fuel for its generating plants. SoCalGas owns and operates a natural gas distribution, transmission and storage system that supplies natural gas in 535 cities and communities throughout a 23,000-square-mile service territory comprising most of southern and part of central California. Supplies of Natural Gas The Company buys natural gas under several short-term and long-term contracts. Short-term purchases are based on monthly-spot-market prices. The Company has firm pipeline capacity contracts with pipeline companies that expire at various dates through 2023. Most of the natural gas purchased and delivered by the Company is produced outside of California. These supplies are delivered to the Company's intrastate transmission system by interstate pipeline companies, primarily El Paso Natural Gas Company and Transwestern Natural Gas Company. These interstate companies provide transportation services for supplies purchased from the Company's transportation customers or other sources. The rates that interstate pipeline companies may charge for natural gas and transportation services are regulated by the FERC. Existing pipeline capacity into California exceeds current demand by over 1 billion cubic feet (bcf) per day. The implications of this excess are described in "Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 1998 Annual Report to Shareholders, which is incorporated by reference. The following table shows the sources of natural gas deliveries from 1994 through 1998. Year Ended December 31 ------------------------------------------------------------------- 1998 1997 1996 1995 1994 - ------------------------------------------------------------------------------------------------------------- Natural Gas Purchases (billions of cubic feet): Market 388 330 323 296 342 Long-Term Contracts 104 100 108 128 137 ------- ------- ------- ------- ------- Total Gas Purchases 492 430 431 424 479 Customer-Owned and Exchange Receipts 521 514 422 531 565 Storage Withdrawal (Injection) - Net (28) (3) 42 (13) (9) Company Use and Unaccounted For (23) (11) (11) (5) (15) ------- ------- ------- ------- ------- Net Deliveries 962 930 884 937 1,020 ======= ======= ======= ======= ======= Natural Gas Purchases: (millions of dollars) Commodity Costs $1,092 $1,160 $ 879 $ 666 $ 890 Fixed Charges* 174 250 276 264 368 ------- ------- ------- ------- ------- Total Gas Purchases $1,266 $1,410 $1,155 $ 930 $1,258 ======= ======= ======= ======= ======= Average Commodity Cost of Gas Purchased (Dollars per Thousand Cubic Feet) $ 2.22 $ 2.69 $ 2.04 $ 1.57 $ 1.86 ======= ======= ======= ======= ======= * Fixed charges primarily include pipeline demand charges, take or pay settlement costs, and other direct-billed amounts allocated over the quantities delivered by the interstate pipelines serving SoCalGas. Market-sensitive natural gas supplies (supplies purchased on the spot market as well as under longer-term contracts ranging from one month to ten years based on spot prices) accounted for 79 percent of total natural gas volumes purchased by the Company during 1998, as compared with 77 percent and 75 percent during 1997 and 1996, respectively. These supplies were generally purchased at prices significantly below those of long-term sources of supply. During 1998, the Company delivered 962 bcf of natural gas through its system. Approximately 54 percent of these deliveries were customer-owned natural gas for which the Company provided transportation services. The balance of natural gas deliveries was gas purchased by the Company and resold to customers. 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 5.6 million core customers (5.4 million residential and 230,000 small commercial and industrial). Noncore customers consist primarily of utility electric generation (UEG), wholesale, and large commercial and industrial customers, and total 1,700. 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. In 1998 for SoCalGas, 87 percent of the CPUC-authorized natural gas margin was allocated to the core customers, with 13 percent allocated to the noncore customers. In 1998 for SDG&E, 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 throughput are 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. The Company also provides natural gas storage services for noncore and off-system customers on a bid and negotiated contract basis. The storage service program provides opportunities for customers to store natural gas on an "as available" basis, usually during the summer to reduce winter purchases when natural gas costs are generally higher. As of December 31, 1998, the Company stored approximately 26 bcf of customer-owned gas. 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 58,000 new customers in 1998. This represents a growth rate of 1.0 percent. The Company expects its growth for 1999 will continue at about the 1998 level. During 1998, 97 percent of residential energy customers in the Company's service area used natural gas for water heating, 94 percent for space heating, 78 percent for cooking and 72 percent for clothes drying. 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 1,700, it accounted for approximately 12 percent of the authorized natural gas revenues and 57 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 large UEG customers is also greatly affected by the price and availability of electric power generated in other areas and purchased by the Company's UEG customers. Natural gas demand in 1998 for UEG customer use decreased as a result of decreased demand for electricity. UEG customer demand increased in 1997 as a result of higher demand for electricity and less availability of hydro- electricity. As a result of electric industry restructuring, natural gas demand for electric generation within southern California competes with electric power generated throughout the western United States. Effective March 31, 1998, California consumers were given the option of selecting their electric energy provider from a variety of local and out-of-state producers. Although the electric industry restructuring has no direct impact on the Company's natural-gas operations, future volumes of natural gas transported for UEG customers may be adversely affected to the extent that regulatory changes divert electricity from the Company's service area. 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 13 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. ELECTRIC OPERATIONS Resource Planning In September 1996, California enacted a law restructuring California's electric-utility industry. 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. Additional information concerning electric-industry restructuring is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 13 and 14 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. 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 sell. 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 6, 13 and 14 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. 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 13 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. Power Pools In 1964 SDG&E, Pacific Gas & Electric (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 elsewhere herein) 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" of the 1998 Annual Report to Shareholders, which is incorporated by reference. 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 13 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. INTERNATIONAL OPERATIONS Sempra Energy International (SEI) develops, operates and invests in energy infrastructure projects, including natural gas distribution systems and power generation facilities, outside of the United States. In August 1998, SEI was awarded a 10-year agreement by the Mexican Federal Electric Commission (CFE) to supply natural gas to an electric power plant in Rosarito, Baja California. The terms of the agreement include a provision to construct a pipeline from the US - Mexico border to the plant and call for SEI to provide a complete energy supply package. In addition, SEI and Proxima Gas S.A. de C.V., as partners in the Mexican companies Distribuidora de Gas Natural (DGN) de Mexicali and Distribuidora de Gas Natural (DGN) de Chihuahua, operate natural gas distribution systems in Mexicali and Chihuahua, Mexico. SEI also has interests in natural gas distribution partnerships in Argentina and Uruguay. In March 1998, SEI increased its existing investment in two Argentine natural gas utility holding companies (Sodigas Pampeana S.A. and Sodigas Sur S.S.) from 12.5 percent to 21.5 percent, by purchasing an additional interest for $40 million. The net losses for international operations were $4 million and $9 million, after-tax, for 1998 and 1997, respectively. Additional information on international operations is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 3 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. SEMPRA ENERGY TRADING (SET) SET, a leading natural gas and power marketing firm headquartered in Stamford, Connecticut, was jointly acquired by Pacific Enterprises (PE) and Enova Corporation (Enova) on December 31, 1997. (PE and Enova combined to form Sempra Energy in June 1998.) In July 1998, SET purchased a wholesale trading and commercial marketing subsidiary of Consolidated Natural Gas, to expand its operation in the eastern United States. SET derives a substantial portion of its revenue from market making and trading activities, as a principal, in natural gas, petroleum and electricity. It quotes bid and offer prices to end users and other market makers. It also earns trading profits as a dealer by structuring and executing transactions that permit its counterparties to manage their risk profiles. In addition, it takes positions in energy markets based on the expectation of future market conditions. For the year ended December 31, 1998, SET had operating revenues of $110 million and after-tax net losses of $13 million. The losses were due to the amortization of costs associated with the acquisition by PE and Enova. Additional information on SET is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 3 and 10 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. RATES AND REGULATION The Company's principal subsidiaries, SoCalGas and SDG&E, are regulated by the CPUC. The CPUC 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 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 14 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. 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 14 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. 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 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" of the 1998 Annual Report to Shareholders, which is incorporated by reference. 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 both SoCalGas and 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 14 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. 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 subject to the limitations of the Gas Cost Incentive Mechanism (GCIM) discussed below. The BCAP will continue under PBR. Additional information on the BCAP is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 14 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. Gas Cost Incentive Mechanism (GCIM) The GCIM is a process SoCalGas uses to evaluate its natural-gas purchases, substantially replacing the previous process of reasonableness reviews. Additional information on the GCIM is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 14 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. 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 14 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. Cost of Capital Under PBR, annual Cost of Capital proceedings have been replaced by an automatic adjustment mechanism if changes in certain indicies exceed established tolerances. For 1999, SoCalGas is authorized to earn a rate of return on rate base (ROR) of 9.49 percent and a rate of return on common equity (ROE) of 11.6 percent, the same as in 1998, unless interest-rate changes are large enough to trigger an automatic adjustment. 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 an ROE of 11.6 percent and an ROR of 9.35 percent. Additional information on the utilities' cost of capital is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 14 of the "Notes to Consolidated Financial Statements" of the 1998 Annual Report to Shareholders, which is incorporated by reference. ENVIRONMENTAL MATTERS Discussions about environmental issues affecting the Company are included in "Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 1998 Annual Report to Shareholders, which is incorporated by reference. The following should be read in conjunction with those discussions. Hazardous Substances The utilities 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 jurisdictions 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 utilities and others who disposed of hazardous wastes at the facility. The Redevelopment Agency for the City of San Diego has exerted this authority affecting Station A and adjacent properties to accommodate a major league ballpark and ancillary development proposed by the City. During the early 1900s, the Company and its predecessors manufactured gas from coal and oil at its 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. Initial cleanup actions commenced in 1998, and are expected to be completed in 1999, at an estimated cost of $5 million. The Company is negotiating with the redevelopment 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 redevelopment agency will retain its rights to enforce the cleanup in the event the Company did not complete it. Contaminants resulting from the gas-manufacturing process by-products were assessed at the Company's 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, the Company 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. The Company is in the process of selling its electric-generating assets. As a part of its environmental due diligence, the Company 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 the Company's other transition costs. The Company and its subsidiaries have been named as potential responsible parties (PRPs) for two landfill sites and three industrial waste disposal sites, as described below. The Casmalia former waste disposal site operated as a Class I waste disposal site which was composed of 6 landfills, 58 surface impoundments, 11 disposal wells, 7 disposal trenches, 2 treatment systems and one former pre-Resource Conservation and Recovery Act drum burial area. The Company has estimated the costs of remediation at Casmalia to be $1.1 million. In 1998, the Company completed work efforts of $225,241. Remedial actions and negotiations with other PRPs and the United States Environmental Protection Agency (EPA) have been continuing since March 1993. The Company is currently negotiating a final remedy with the EPA for Operating Industries, Inc. (OII), a former landfill for both household and industrial wastes. The total costs for remediation of OII are estimated at $3 million, of which $644,133 was completed during 1998. Remedial actions and negotiations have been in progress since June 1986. In the early 1990s, the Company was notified of hazards at two former industrial waste treatment facilities, Industrial Waste Processing (Industrial) and Cal Compact (Compact), where the Company had disposed of wastes. A feasibility study and remedial investigation have been submitted and accepted by the EPA for Industrial. The total cost estimate for remediation of Industrial is $300,000, of which approximately $3,700 of remedial action was completed in 1998. The nature and extent for remediation of the Compact site is estimated to be $120,000. During 1998, the Company completed remedial efforts of this site at a cost of $48,000 and is involved in ongoing negotiations with the California Department of Toxic Substances Control (DTSC). The Company and 10 other entities have also been named PRPs by the DTSC as liable for any required corrective action regarding contamination at a site in Pico Rivera, California. DTSC has taken this action because the Company and others sold used electrical transformers to the site's owner. The DTSC considers the Company 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 Company's estimated remaining investigation and remediation liability related to hazardous waste sites not detailed above was $83 million, of which 90 percent is authorized to be recovered through the Hazardous Waste Collaborative mechanism. The Company 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 its 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 SDG&E's Rule 69 compliance costs to increase. Wastewater discharge permits issued by the Regional Water Quality Control Board (RWQCB) for the Company'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, the Company 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 off-shore 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 Company for the South Bay power plant. The Company filed an appeal to the State Water Resources Control Board (SWRCB) of various provisions which SDG&E 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 the Company thereafter appealed to the San Diego County Superior Court. These latter issues were subsequently settled through negotiations between the Company and the RWQCB. All of the settled issues have been incorporated into the November 1996 NPDES 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. The Company cannot predict the cost of such cleanup. In May 1987 the RWQCB issued the Company a cleanup and abatement order for gasoline contamination originating from an underground storage tank located at the Company'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. The Company 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" of the 1998 Annual Report to Shareholders, which is incorporated by reference. Wages The utilities employ over 9,000 persons. Field, technical and most clerical employees at SoCalGas area are represented by the Utility Workers' Union of America or the International Chemical Workers' Council. The collective bargaining agreement on wages, hours and working conditions remains in effect through March 31, 2000. Employees at SDG&E are represented by the Local 465 International Brotherhood of Electrical Workers with two labor agreements. The generation contract runs through February 28, 2001 and negotiations for the utility contract (transmission and distribution) are ongoing. Employees of Registrant As of December 31, 1998 the Company had 11,148 employees, compared to 11,387 at December 31, 1997. The employment level decreased due to synergies resulting from the Enova and Pacific Enterprises business combination. ITEM 2. PROPERTIES Electric Properties The Company's generating capacity is described in "Electric Resources" herein. The Company'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 At December 31, 1998, the Company owned approximately 3,024 miles of transmission and storage pipeline, 50,955 miles of distribution pipeline and 49,520 miles of service piping. It also owned 12 transmission compressor stations and 6 underground storage reservoirs (with a combined working storage capacity of approximately 116 Bcf). Other Properties The 21-story corporate headquarters building at 101 Ash Street, San Diego, is occupied pursuant to a capital lease through the year 2005. The lease has four separate five-year renewal options. Southern California Gas Tower, a wholly owned subsidiary of SoCalGas, has a 15-percent limited partnership interest in a 52- story office building in downtown Los Angeles. SoCalGas leases approximately half of the building through the year 2011. The lease has six separate five-year renewal options. 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. The Company 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 incorporated by reference in Item 8 or referred to elsewhere in this Annual Report, neither Sempra Energy nor any of its subsidiaries is a party to, nor is their 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 - --------------------------------------------------------------------- Richard D. Farman 63 Chairman and Chief Executive Officer Stephen L. Baum 57 Vice Chairman, President and Chief Operating Officer Donald E. Felsinger 51 Group President - Nonregulated Business Units Warren I. Mitchell 61 Group President - Regulated Business Units John R. Light 57 Executive Vice President and General Counsel Neal E. Schmale 52 Executive Vice President and Chief Financial Officer Jerry D. Florence 50 Senior Vice President - Corporate Communications Frederick E. John 52 Senior Vice President - External Affairs Margot A. Kyd 45 Senior Vice President and Chief Administrative Officer Frank H. Ault 54 Vice President and Controller * As of December 31, 1998. Each Executive Officer has been an officer of the Company or one of its subsidiaries for more than five years, with the exception of Mssrs. Light, Schmale and Florence. Prior to joining the Company in 1998, Mr. Light was a partner in the law firm of Latham & Watkins. Prior to joining the Company in 1997, Mr. Schmale was Chief Financial Officer of Unocal Corporation. Prior to joining the Company in 1998, Mr. Florence held officer positions with Nissan North America, Inc. and Nissan Motor Corporation, U.S.A. PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Common stock of Sempra Energy is traded on the New York and Pacific stock exchanges. At February 28, 1999 there were approximately 100,000 holders of record of the Company's common stock. The quarterly common stock information required by Item 5 is included in the schedule of Quarterly Financial Data of the 1998 Annual Report to Shareholders, which is incorporated by reference. Dividend Restrictions At December 31, 1998, $699 million of the Company's retained earnings was available for future dividends due to the CPUC's regulation of the utilities' capital structure. Additional information is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 1998 Annual Report to Shareholders, which is incorporated by reference. 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: Revenues and other income $ 5,525 $ 5,127 $ 4,524 $ 4,201 $ 4,539 Operating income $ 639 $ 939 $ 927 $ 886 $ 867 Net income $ 294 $ 432 $ 427 $ 401 $ 296 Balance Sheet Data: Total assets $10,456 $10,756 $ 9,762 $ 9,837 $ 9,931 Long-term debt $ 2,795 $ 3,175 $ 2,704 $ 2,721 $ 2,889 Short-term debt (a) $ 373 $ 624 $ 481 $ 485 $ 645 Shareholders' equity $ 2,913 $ 2,959 $ 2,930 $ 2,815 $ 2,684 Per Share Data Net income per common share: Basic $ 1.24 $ 1.83 $ 1.77 $ 1.67 $ 1.23 Diluted $ 1.24 $ 1.82 $ 1.77 $ 1.67 $ 1.23 Dividends declared Per common share $ 1.56 $ 1.27 $ 1.24 $ 1.22 $ 1.16 Book value per common share $ 12.29 $ 12.56 $ 12.21 $ 11.70 $ 11.18 (a) Includes bank and other notes payable, commercial paper borrowings and long-term debt due within one year. This data should be read in conjunction with the Consolidated Financial Statements and notes to Consolidated Financial Statements contained in the 1998 Annual Report to Shareholders, which is incorporated by reference. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The information required by Item 7 is incorporated by reference from pages 21 through 36 of the 1998 Annual Report to Shareholders. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required by Item 7A is incorporated by reference from pages 34 through 35 and from Note 10 of the notes to Consolidated Financial Statements of the 1998 Annual Report to Shareholders. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required by Item 8 is incorporated by reference from pages 39 through 71 of the 1998 Annual Report to Shareholders. See Item 14 for a listing of financial statements included in the 1998 Annual Report to Shareholders. 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 Proxy 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 Proxy 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 Proxy 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 Annual Report* Statement of Management Responsibility for Consolidated Financial Statements. . . . . . . . . . . 38 Independent Auditors' Report . . . . . . . . . . . . . . 38 Statements of Consolidated Income for the years ended December 31, 1998, 1997 and 1996 . . . . . . . . 39 Consolidated Balance Sheets at December 31, 1998 and 1997. . . . . . . . . . . . . . . . . . . . . 40 Statements of Consolidated Cash Flows for the years ended December 31, 1998, 1997 and 1996 . . . . . 42 Statements of Consolidated Changes in Shareholders' Equity for the years ended December 31, 1998, 1997 and 1996 . . . . . . . . . . . 44 Notes to Consolidated Financial Statements . . . . . . . 45 Quarterly Financial Data (Unaudited) . . . . . . . . . . 71 *Incorporated by reference from the indicated pages of the 1998 Annual Report to Shareholders. 2. Financial statement schedules The following documents may be found in this report at the indicated page numbers. Independent Auditors' Consent and Report on Schedule. . . . . . . . . . . . . . . . . . 27 Schedule I--Condensed Financial Information of Parent. . 28 Any other 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 of the 1998 Annual Report to Shareholders. 3. Exhibits See Exhibit Index on page 31 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. A Current Report on Form 8-K filed February 23, 1999 announced the agreement entered into by Sempra Energy and KN Energy, Inc. to merge the two companies. INDEPENDENT AUDITORS' CONSENT AND REPORT ON SCHEDULE To the Board of Directors and Shareholders of Sempra Energy: We consent to the incorporation by reference in Registration Statement Number 333-51309 on Form S-3 and Registration Statement Number 333-56161 on Form S-8 of Sempra Energy of our report dated January 27, 1999, except for Note 16 as to which the date is February 22, 1999, incorporated by reference in the Annual Report on Form 10-K of Sempra Energy for the year ended December 31, 1998. Our audits of the financial statements referred to in our aforementioned report also included the financial statement schedule of Sempra Energy, listed in Item 14. This financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein. DELOITTE & TOUCHE LLP San Diego, California March 9, 1999 Schedule I -- CONDENSED FINANCIAL INFORMATION OF PARENT SEMPRA ENERGY Schedule 1 Condensed Financial Information of Parent Condensed Statement of Income (Dollars in millions, except per share amounts) For the year ended December 31 1998 ---------- Operating revenues and other income $ - Operating expenses, interest and income taxes 10 ---------- Loss before subsidiary earnings (10) Subsidiary earnings 304 ---------- Earnings applicable to common shares $ 294 ========== Average common shares outstanding (basic) 236,423 ---------- Average common shares outstanding (diluted) 237,124 ---------- Earnings per common share (basic) $ 1.24 ---------- Earnings per common share (diluted) $ 1.24 ========== Condensed Balance Sheet (Dollars in millions) Balance at December 31 1998 ---------- Assets: Cash and temporary investments $ 67 Dividends receivable 100 Other current assets 174 ---------- Total current assets 341 Investments in subsidiaries 2,820 Deferred charges and other assets 106 ---------- Total Assets $ 3,267 ========== Liabilities and Shareholders' Equity: Dividends payable $ 93 Other current liabilities 221 ---------- Total current liabilities 314 Long-term liabilities 40 Common equity 2,913 ---------- Total Liabilities and Shareholders' Equity $ 3,267 ========== SEMPRA ENERGY Schedule 1 (continued) Condensed Financial Information of Parent Condensed Statement of Cash Flows (Dollars in millions) For the year ended December 31 1998 --------- Cash flows from operating activities $ 71 --------- Sale of common stock 4 Dividends paid (94) --------- Cash flows from financing activities (90) --------- Expenditures for property, plant and equipment (44) Dividends received from subsidiaries 130 --------- Cash flows from investing activities 86 --------- Net cash flow 67 Cash and temporary investments, beginning of year -- --------- Cash and temporary investments, end of year $ 67 ========= Non cash dividends received from subsidiaries $ 597 ========= 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. SEMPRA ENERGY By: /s/ Richard D. Farman . Richard D. Farman Chairman and Chief Executive 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: Richard D. Farman Chairman, Chief Executive Officer /s/Richard D. Farman March 2, 1999 Stephen L. Baum Vice Chairman, President, Chief Operating Officer /s/Stephen L. Baum March 2, 1999 Principal Financial Officer: Neal E. Schmale Executive Vice President, Chief Financial Officer /s/Neal E. Schmale March 2, 1999 Principal Accounting Officer: Frank H. Ault Vice President, Controller /s/Frank H. Ault March 2, 1999 Directors: Richard D. Farman Chairman /s/Richard D. Farman March 2, 1999 Stephen L. Baum Vice Chairman /s/Stephen L. Baum 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, 8-B/A, 8-K, S-4, 10-K and 10-Q referred to herein were filed under Commission File Number 1-40 (Pacific Enterprises), Commission File Number 1-3779 (San Diego Gas & Electric), Commission File Number 1-1402 (Southern California Gas Company), Commission File Number 1-11439 (Enova Corporation) and/or Commission File Number 333-30761 (SDG&E Funding LLC). 3.a The following exhibits relate to Sempra Energy and its subsidiaries Exhibit 1 -- Underwriting Agreements Enova Corporation and San Diego Gas & Electric Company (SDG&E) - -------------------------------------------------------------- 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 2 -- Plan of Acquisition, reorganization, arrangement, liquidation, or succession Sempra Energy - ------------- 2.01 Agreement and Plan of Merger (the "Merger Agreement"), dated as of February 20, 1999, among the Company, Cardinal Acquisition Corp., a California corporation, and KN Energy, Inc., a Kansas corporation ("KN"). (Incorporated by reference from Form 8-K filed by Sempra Energy filed on February 23, 1999.) Exhibit 3 -- Bylaws and Articles of Incorporation Bylaws Sempra Energy - ------------- 3.01 Amended and Restated Bylaws of Sempra Energy effective May 26, 1998 (Incorporated by reference from the Registration Statement on Form S-8 Sempra Energy Registration No. 333-56161 dated June 5, 1998(Exhibit 3.2)) . Articles of Incorporation Sempra Energy - ------------- 3.02 Amended and Restated Articles of Incorporation of Sempra Energy (Incorporated by reference to the Registration Statement on Form S-3 File No. 333-51309 dated April 29, 1998, 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. Enova Corporation and San Diego Gas & Electric Company (SDG&E) - -------------------------------------------------------------- 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.) Pacific Enterprises - ------------------- 4.07 Rights Agreement dated as of March 7, 1990 between Pacific Enterprises and Security Pacific National Bank, as Rights Agent (Pacific Enterprises September 25, 1992 Form 8-K; Exhibit 4). Pacific Enterprises/Southern California Gas - ------------------------------------------- 4.09 First Mortgage Indenture of Southern California Gas Company to American Trust Company dated as of October 1, 1940 (Registration Statement No. 2-4504 filed by Southern California Gas Company on September 16, 1940; Exhibit B-4). 4.10 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of July 1, 1947 (Registration Statement No. 2- 7072 filed by Southern California Gas Company on March 15, 1947; Exhibit B-5). 4.11 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of August 1, 1955 (Registration Statement No. 2-11997 filed by Pacific Lighting Corporation on October 26, 1955; Exhibit 4.07). 4.12 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of June 1, 1956 (Registration Statement No. 2-12456 filed by Southern California Gas Company on April 23, 1956; Exhibit 2.08). 4.13 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of August 1, 1972 (Registration Statement No. 2-59832 filed by Southern California Gas Company on September 6, 1977; Exhibit 2.19). 4.14 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of May 1, 1976 (Registration Statement No. 2-56034 filed by Southern California Gas Company on April 14, 1976; Exhibit 2.20). 4.15 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of September 15, 1981 (Pacific Enterprises 1981 Form 10-K; Exhibit 4.25). 4.16 Supplemental Indenture of Southern California Gas Company to Manufacturers Hanover Trust Company of California, successor to Wells Fargo Bank, National Association, and Crocker National Bank as Successor Trustee dated as of May 18, 1984 (Southern California Gas Company 1984 Form 10-K; Exhibit 4.29). 4.17 Supplemental Indenture of Southern California Gas Company to Bankers Trust Company of California, N.A., successor to Wells Fargo Bank, National Association dated as of January 15, 1988 (Pacific Enterprises 1987 Form 10-K; Exhibit 4.11). 4.18 Supplemental Indenture of Southern California Gas Company to First Trust of California, National Association, successor to Bankers Trust Company of California, N.A. dated as of August 15, 1992 (Registration Statement No. 33-50826 filed by Southern California Gas Company on August 13, 1992; Exhibit 4.37). Exhibit 10 -- Material Contracts (Previously filed exhibits are incorporated by reference from Forms 8-K, S-4, 10-K or 10-Q as referenced below). Sempra Energy - ------------- 10.01 Amendment to Employment Agreement, effective December 1, 1998. (Employment agreement, dated as of October 12, 1996 between Mineral Energy Company and Stephen L. Baum (Enova 8-K filed October 15,1996, Exhibit 10.2)) 10.02 Amendment to Employment Agreement effective December 1, 1998. (Employment contract dated as of October 12, 1996 between Mineral Energy Company and Richard D. Farman (Enova 8-K filed October 15, 1996, Exhibit 10.3)). 10.03 Amendment to Employment Agreement effective December 1, 1998. (Employment contract, dated as of October 12, 1996 between Mineral Energy Company and Donald E. Felsinger (Enova 8-K filed October 15, 1996, Exhibit 10.4)). 10.04 Amendment to Employment Agreement effective December 1, 1998. (Employment contract, dated as of October 12, 1996 between Mineral Energy Company and Warren I. Mitchell (Enova 8-K filed October 15, 1996, Exhibit 10.5)). Enova Corporation and San Diego Gas & Electric Company (SDG&E) - -------------------------------------------------------------- 10.05 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)). 10.06 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)). Pacific Enterprises - -------------------- 10.07 Form of Indemnification Agreement between Pacific Enterprises and each of its directors and officers (Pacific Enterprises 1992 Form 10-K Exhibit 10.07). 10.08 Operating Agreement of Mineral JV, LLC, dated as of January 13, 1997 (Registration Statement No. 333-21229 filed by Mineral Energy Company on February 5, 1997, Exhibit 10.5). Compensation Sempra Energy - ------------- 10.09 Sempra Energy Supplemental Executive Retirement Plan as amended and restated effective July 1, 1998 10.10 Sempra Energy Deferred Compensation Agreement for Directors effective June 1, 1998. 10.11 Sempra Energy Executive Incentive Plan effective June 1, 1998 10.12 Sempra Energy Executive Deferred Compensation Agreement effective June 1, 1998 10.13 Sempra Energy Retirement Plan for Directors effective June 1, 1998 10.14 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 (Exhibit 4.1)). 10.15 Sempra Energy 1998 Non-Employee Directors' Stock Plan.(Incorporated by reference from the Registration Statement on Form S-8 Sempra Energy Registration No. 333-56161 dated June 5, 1998(Exhibit 4.2)). 10.16 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(Exhibit 4.3)). 10.17 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(Exhibit 4.4)). 10.18 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(Exhibit 4.5)). Enova Corporation and San Diego Gas & Electric (SDG&E) - ------------------------------------------------------ 10.19 Form of Amendment to San Diego Gas & Electric Company Deferred Compensation Agreements for Officers #1 and #3 (1996 Form 10-K Exhibit 10.6). 10.20 Form of Enova Corporation 1998 Deferred Compensation Agreement for Officers #1 (1998 compensation, 1998 bonus) (1997 Enova Form 10-K Exhibit 10.15). 10.21 Form of Enova Corporation 1997 Deferred Compensation Agreement for Officers #1 (1997 compensation, 1998 bonus) (1996 Form 10-K Exhibit 10.7). 10.22 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). 10.23 Form of Enova Corporation 1998 Deferred Compensation Agreement for Officers #3. (1997 Enova Form 10-K Exhibit 10.12). 10.24 Form of Enova Corporation 1997 Deferred Compensation Agreement for Officers #3 (1997 compensation, 1998 bonus)(1996 Form 10-K Exhibit 10.10). 10.25 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). 10.26 Form of Enova Corporation 1998 Deferred Compensation Agreement for Nonemployee Directors. (1997 Enova Form 10-K Exhibit 10.16). 10.27 Form of Enova Corporation 1997 Deferred Compensation Agreement for Nonemployee Directors (1996 Form 10-K Exhibit 10.13). 10.28 Form of San Diego Gas & Electric Company Deferred Compensation Agreement for Nonemployee Directors (1996 compensation)(1995 SDG&E Form 10-K Exhibit 10.5). 10.29 Form of Enova Corporation 1986 Long-Term Incentive Plan 1997 restricted stock award agreement. (1997 Enova Form 10-K Exhibit 10.18). 10.30 Form of Enova Corporation 1986 Long-Term Incentive Plan 1996 restricted stock award agreement (1996 Form 10-K Exhibit 10.16). 10.31 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). 10.32 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). 10.33 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). 10.34 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). 10.35 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). 10.36 Amended 1986 Long-Term Incentive Plan, Restatement as of October 25, 1993 (1993 SDG&E Form 10-K Exhibit 10.6). 10.37 San Diego Gas & Electric Company Severance Plan effective October 22, 1996 (1996 Form 10-K Exhibit 10.24). 10.38 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). 10.39 San Diego Gas & Electric Company Retirement Plan for Directors, restated as of October 24, 1994 (1994 SDG&E Form 10-K Exhibit 10.5). 10.40 Executive Incentive Plan dated April 23, 1985 (1991 SDG&E Form 10-K Exhibit 10.39). 10.41 Employment agreement between San Diego Gas & Electric Company and Thomas A. Page, dated June 15, 1988 (1988 SDG&E Form 10-K Exhibit 10E). 10.42 Supplemental Pension Agreement with Thomas A. Page, dated as of April 3, 1978 (1988 SDG&E Form 10-K Exhibit 10V). 10.43 Supplemental Executive Retirement Plan restated as of July 1, 1994 (1994 SDG&E Form 10-K Exhibit 10.14). Pacific Enterprises/Southern California Gas Company - --------------------------------------------------- 10.44 Restatement and Amendment of Pacific Enterprises 1979 Stock Option Plan (Registration Statement No. 2-66833 filed by Pacific Lighting Corporation on March 5, 1980, Exhibit 1.1). 10.45 Pacific Enterprises Supplemental Medical Reimbursement Plan for Senior Officers (Pacific Lighting Corporation 1980 Form 10-K Exhibit 10.24). 10.46 Pacific Enterprises Financial Services Program for Senior Officers (Pacific Lighting Corporation 1980 Form 10-K Exhibit 10.25). 10.47 Pacific Enterprises Supplemental Retirement and Survivor Plan (Pacific Lighting Corporation 1984 Form 10-K Exhibit 10.36). 10.48 Pacific Enterprises Stock Payment Plan (Pacific Lighting Corporation 1984 Form 10-K Exhibit 10.37). 10.49 Pacific Enterprises Pension Restoration Plan (Pacific Lighting Corporation 1980 Form 10-K Exhibit 10.28). 10.50 Southern California Gas Company Pension Restoration Plan For Certain Management Employees (Pacific Lighting Corporation 1980 Form 10-K Exhibit 10.29). 10.51 Pacific Enterprises Executive Incentive Plan (Pacific Enterprises 1987 Form 10-K; Exhibit 10.13). 10.52 Pacific Enterprises Deferred Compensation Plan for Key Management Employees (Pacific Lighting Corporation 1985 Form 10-K Exhibit 10.41). 10.53 Pacific Enterprises Employee Stock Ownership Plan and Trust Agreement as amended effective October 1, 1992. (Pacific Enterprises 1992 Form 10-K Exhibit 10.18). 10.54 Pacific Enterprises Stock Incentive Plan (Registration Statement No. 33-21908 filed by Pacific Enterprises on May 17, 1988 Exhibit 4.01). 10.55 Pacific Enterprises Retirement Plan for Directors (Pacific Enterprises 1992 Form 10-K Exhibit 10.20). 10.56 Pacific Enterprises Director's Deferred Compensation Plan (Pacific Enterprises 1992 Form 10-K; Exhibit 10.21). 10.57 Amended and Restated Pacific Enterprises Employee Stock Option Plan (as of March 4, 1997) (Pacific Enterprises 1996 Form 10-K Exhibit 10.17). 10.58 Form of Severance Agreement (Pacific Enterprises 1996 Form 10-K Exhibit 10.18). 10.59 Form of Incentive Bonus Agreement (Pacific Enterprises 1996 Form 10-K Exhibit 10.19). Southern California Gas Company - ------------------------------- 10.60 Southern California Gas Company Retirement Savings Plan, as amended and restated as of August 30, 1988 (Registration Statement No. 33-6357 filed by Pacific Enterprises on December 30, 1988; Exhibit 28.02). 10.61 Southern California Gas Company Statement of Life Insurance, Disability Benefit and Pension Plans, as amended and restated as of January 1, 1985 (Southern California Gas Company 1984 Form 10-K; Exhibit 10.27). 10.62 Master Affiliate Service Agreement dated as of September 1, 1996 between Southern California Gas Company and Pacific Enterprises Energy Services, as amended (Southern California Gas Company 1996 Form 10-K; Exhibit 10.11). Financing Enova Corporation and San Diego Gas & Electric (SDG&E) - ------------------------------------------------------ 10.63 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). 10.64 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). 10.65 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). 10.66 Loan agreement with City of San Diego in connection with the issuance of $16.7 million of Industrial Development Bonds, dated as of June 1, 1995 (June 30, 1995 SDG&E Form 10-Q Exhibit 10.2). 10.67 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). 10.68 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). 10.69 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). 10.70 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). 10.71 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). 10.72 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). 10.73 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). 10.74 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). 10.75 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). Natural Gas Commodity, Transportation and Storage Enova Corporation and San Diego Gas & Electric (SDG&E) - ------------------------------------------------------ 10.76 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). 10.77 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). 10.78 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). 10.79 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). 10.80 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). 10.81 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). 10.82 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). 10.83 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). 10.84 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). 10.85 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). 10.86 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) Nuclear Enova Corporation and San Diego Gas & Electric (SDG&E) - ------------------------------------------------------ 10.87 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). 10.88 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). 10.89 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). 10.90 Amendment No. 1 to the Qualified CPUC Decommissioning Master Trust Agreement dated September 22, 1994 (see Exhibit 10.89 herein)(1994 SDG&E Form 10-K Exhibit 10.56). 10.91 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 10.89 herein)(1994 SDG&E Form 10-K Exhibit 10.57). 10.92 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 10.89 herein)(1996 Form 10-K Exhibit 10.59). 10.93 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 10.89 herein)(1996 Form 10-K Exhibit 10.60). 10.94 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). 10.95 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 10.94 herein)(1996 Form 10-K Exhibit 10.62). 10.96 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 10.94 herein)(1996 Form 10-K Exhibit 10.63). 10.97 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). 10.98 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 10.99 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). 10.100 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). Other 10.101 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). 10.102 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). 10.103 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). 10.104 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 10.103 herein)(1994 SDG&E Form 10-K Exhibit 10.72). 10.105 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). 10.106 Assignment of Lease agreement dated as of November 19, 1993 to Shapery Developers as lessor by New England Mutual Life Insurance Company (See Exhibit 10.105 herein)(1994 SDG&E Form 10-K Exhibit 10.74). Exhibit 11 -- Statement re: Computation Of Per Share Earnings 11.01 Sempra Energy Computation of Earnings per Share (see Consolidated Statements of Income and Note 12 of the notes to Consolidated Financial Statements contained in Exhibit 13.01). 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 13 -- Annual Report to Security Holders 13.01 Sempra Energy 1998 Annual Report to Shareholders. (Such report, except for the portions thereof which are expressly incorporated by reference in this Annual Report, is furnished for the information of the Securities and Exchange Commission and is not to be deemed "filed" as part of this Annual Report). Exhibit 21 -- Subsidiaries See Notes 1 and 3 of notes to consolidated financial statements and Management's Discussion and Analysis of Financial Condition and Results of Operations contained in Exhibit 13.01 Exhibit 23 -- Independent Auditors' Consent, page 27. Exhibit 27 -- Financial Data Schedules 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 One Billion Cubic Feet (of natural gas) BRPU Biennial Resource Plan Update 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 and its wholly owned subsidiaries EOR Enhanced Oil Recovery EPS Earnings Per Share ESOP Employee Stock Ownership Plan FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission GCIM Gas Cost Incentive Mechanism GRC General Rate Case IDBs Industrial Development Bonds IOUs Investor-Owned Utilities ISO Independent System Operator IT Information Technology Kv Kilovolt Kwhr Kilowatt Hour LG&E Louisville Gas & Electric Power Marketing 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 OTC Over The Counter 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 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 SEF Sempra Energy Financial SEI Sempra Energy International SER Sempra Energy Resources SES Sempra Energy Solutions SET Sempra Energy Trading SEUV Sempra Energy Utility Ventures SFAS Statement of Financial Accounting Standards SoCalGas Southern California Gas 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 40

EXHIBIT 13.01 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 information about the capital resources, liquidity and financial performance of Sempra Energy and its subsidiaries (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 a California-based Fortune 500 energy-services company whose principal subsidiaries are San Diego Gas & Electric (SDG&E), which provides electric and natural gas service to San Diego County and southern Orange County, and Southern California Gas Company (SoCalGas), the nation's largest natural gas distribution utility, serving 4.8 million meters throughout most of southern California and part of central California. Together, the two utilities serve approximately 7 million meters. Sempra Energy Trading is engaged in the wholesale trading and marketing of natural gas, power and petroleum. Sempra Energy Solutions is engaged in the buying and selling of natural gas for large users, integrated energy-management services targeted at large governmental and commercial facilities, and consumer-market products and services. Sempra Energy Financial invests in limited partnerships representing 1,250 affordable-housing properties throughout the United States. Through other subsidiaries, the company owns and operates interstate and offshore natural gas pipelines and centralized heating and cooling for large building complexes, and is involved in domestic and international energy- utility operations, nonutility electric generation and other energy-related products and services. BUSINESS COMBINATIONS Sempra Energy was formed to serve as a holding company for Pacific Enterprises (the parent corporation of the Southern California Gas Company) and Enova Corporation (the parent corporation of San Diego Gas & Electric Company) in connection with a business combination that became effective on June 26, 1998 (the PE/Enova Business Combination). In January 1998, PE and Enova jointly acquired CES/Way International, Inc. Expenses incurred in connection with these business combinations are $85 million, aftertax, and $20 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 PE and Enova became the holders of the company's common stock. PE's common shareholders received 1.5038 shares of the company's common stock for each share of PE common stock, and Enova's common shareholders received one share of the company's common stock for each share of Enova common stock. The preferred stock of PE 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 the company gave effect to the combination using the pooling-of-interests method and are preserved as if the companies were combined during all periods included therein. CAPITAL RESOURCES AND LIQUIDITY The company's utility operations continue to be a major source of liquidity. In addition, working capital requirements are met primarily through the issuance of short- and long-term debt. Cash requirements primarily include capital investments in the utility operations. Nonutility cash requirements include investments in Sempra Energy Resources, Sempra Energy Utility Ventures, Sempra Energy Solutions, Sempra Energy Trading, CES/Way International, and other domestic and international ventures. Additional information on sources and uses of cash during the last three years is summarized in the following condensed statement of consolidated cash flows: - ------------------------------------------------------------ SOURCES AND (USES) OF CASH Year Ended December 31 (Dollars in millions) 1998 1997 1996 - ------------------------------------------------------------ Operating Activities $1,323 $918 $1,164 ------------------------- Investing Activities: Capital expenditures (438) (397) (413) Acquisitions of subsidiaries (191) (206) (50) Other (50) 1 (51) ------------------------- Total Investing Activities (679) (602) (514) ------------------------- Financing Activities: Common stock dividends (325) (301) (300) Sale of common stock 34 17 8 Repurchase of common stock (1) (122) (24) Redemption of preferred stock (75) _ (225) Long-term debt-net (356) 382 (155) Short-term debt-net (311) 92 29 ------------------------- Total Financing Activities (1,034) 68 (667) ------------------------- Increase (decrease) in cash and cash equivalents $(390) $384 $(17) - ------------------------------------------------------------ CASH FLOWS FROM OPERATING ACTIVITIES The increase in cash flows from operating activities in 1998 was primarily due to lower working-capital requirements for natural gas operations in 1998. This was caused by higher throughput compared to 1997, combined with natural gas costs that were lower than amounts being collected in rates, which resulted in overcollected regulatory balancing accounts at year-end 1998. This increase was partially offset by expenses incurred in connection with the business combinations. The fluctuation in cash flows from operations was also affected by electric-industry restructuring, including the acceleration of depreciation of electric-generating assets, offset by recovery of stranded costs via the competition transition charge and the 10-percent rate reduction reflected in customers' bills in 1998. The decrease in cash flows from operating activities in 1997 was primarily due to greater working-capital requirements for natural gas operations in 1997. This was caused by natural gas costs being higher than amounts collected in rates, resulting in undercollected regulatory balancing accounts at year-end 1997. The cash flow from electric operations for 1997 was consistent with results from 1996. CASH FLOWS FROM INVESTING ACTIVITIES Cash flows from investing activities primarily represent capital expenditures and investments in new businesses. Capital Expenditures Capital expenditures were $41 million higher in 1998 than in 1997 due to greater capital spending at the company's corporate center related to facility improvements and equipment purchases, and at SDG&E related to industry-restructuring needs and improvements to the electric distribution system, partially offset by lower capital spending at SoCalGas. Capital expenditures were $16 million lower in 1997 than in 1996 due to changes in the scope and timing of several major capital projects primarily related to information systems. SoCalGas had lower capital spending related to the customer information system's being completed in early 1996 and other nonrecurring computer system expenditures in 1996. The decrease was partially offset by higher capital expenditures related to the purchase of a data processing facility and a plant expansion at a non-utility subsidiary. SDG&E's capital expenditures were lower due to changes in scope and timing of several major capital projects. At SDG&E, 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, SDG&E and the other owners of SONGS have requested that the CPUC grant authority to begin decommisioning Unit 1 on January 1, 2000. See Note 6 of the notes to the 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 generation facilities. In December 1998, SDG&E entered into agreements to accomplish that. Completion is pending regulatory approvals and is expected during the first half of 1999. See "Electric-Generation Assets" below for further discussion of the divestiture. Anticipated proceeds from these plant assets, net of the assets' book value, the costs of the sales and certain environmental cleanup costs, will be applied for accounting purposes directly to the recovery of SDG&E'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 at the utilities are estimated to be $419 million in 1999. They will be financed primarily by internally generated funds and will largely represent investment in utility operations. The level of capital expenditures in the next few years will depend heavily on the impact of electric-industry restructuring and the timing and extent of expenditures to comply with environmental requirements. Investments In December 1997, PE and Enova jointly acquired Sempra Energy Trading for $225 million. In July 1998, Sempra Energy Trading purchased a subsidiary of Consolidated Natural Gas, a wholesale trading and commercial marketing operation, for $36 million to expand its operation in the eastern United States. In December 1997, Sempra Energy Resources and Reliant Energy Power Generation formed El Dorado Energy, a joint venture to build, own and operate a natural gas power plant in Boulder City, Nevada. Sempra Energy Resources invested $19.7 million and $2.3 million in El Dorado Energy in 1998 and 1997, respectively. Total cost of the project is projected to be $263 million. In October 1998, El Dorado Energy obtained a 15-year, $158-million, senior secured credit facility to finance the project. This financing represents approximately 60 percent of the estimated total project costs. In September 1997, Sempra Energy Utility Ventures formed a joint venture with Bangor Hydro to build, own and operate a $40 million natural gas distribution system in Bangor, Maine. The project is under construction and is expected to be operational in the fourth quarter of 1999. In December 1997, Sempra Energy Utility Ventures entered into a partnership with Frontier Utilities of North Carolina to build and operate a $55 million natural gas distribution system in North Carolina. Gas delivery began in December 1998. Subsequent to December 31, 1998, Sempra Energy Utilities Ventures acquired 100 percent ownership of the system. In May 1997, Sempra Energy Solutions, together with Conectiv Thermal Systems, Inc., formed two joint ventures to provide integrated energy management services to commercial and industrial customers. Specific projects of these joint ventures are described in Note 3 of the notes to Consolidated Financial Statements. As noted above, Sempra Energy Solutions acquired CES/Way International, Inc. (CES/Way) in 1998. CES/Way provides energy- efficiency services, including energy audits, engineering design, project management, construction, financing and contract maintenance. In March 1998, the company increased its existing investment in two Argentine natural gas utility holding companies from 12.5 percent to 21.5 percent by purchasing an additional interest for $40 million. Fluctuations in Sempra Energy's level of investments in the next few years will depend primarily on the activities of its subsidiaries other than SoCalGas and SDG&E. CASH FLOWS FROM FINANCING ACTIVITIES Net cash used in financing activities increased in 1998 due to greater short- and long-term debt repayments and the redemption of preferred stock in 1998, and the issuance of rate-reduction bonds in 1997, partially offset by the repurchase of common stock in 1997. Net cash was provided by financing activities in 1997 compared to net cash being used in 1996 due to the issuance of rate reduction bonds and lower repayments of long-term debt in 1997, and the redemption of preferred stock in 1996, partially offset by the redemption of common stock in 1997. Long-Term Debt In December 1997, $658 million of Rate Reduction Bonds were issued on SDG&E's behalf at an average interest rate of 6.26 percent. A portion of the bond proceeds was used to retire variable-rate, taxable Industrial Development Bonds (IDBs). Additional information concerning the Rate Reduction Bonds is provided below under "Electric Industry Restructuring." In 1998, cash was used for the repayment of $247 million of first-mortgage bonds, and $66 million of rate-reduction bonds. Short-term debt repayments included repayment of $94 million of debt issued to finance SoCalGas' Comprehensive Settlement as discussed in Note 14 of the notes to Consolidated Financial Statements. In 1997, cash was used for the repayment of $96 million of debt issued to finance the Comprehensive Settlement and repayment of $252 million of SoCalGas' first-mortgage bonds. This was partially offset by the issuance of $120 million in medium-term notes and short-term borrowings used to finance working capital requirements at SoCalGas. 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 consists of variable-rate IDBs. The CPUC has approved specific ratemaking treatment which allows SDG&E to offset IDBs as long as there is at least a like amount of temporary investments. If and when SDG&E requires all or a portion of the $83 million of IDBs to meet future needs for long-term debt, such as to finance new construction, the amount of investments which are being maintained will be reduced below $83 million and the level of IDBs being offset will be reduced by the same amount. Stock Purchases and Redemptions The company, through PE and Enova, repurchased $1 million, $122 million and $24 million of common stock in 1998, 1997 and 1996, respectively. The stock repurchase programs of PE and Enova were suspended as a result of the PE/Enova Business Combination. Sempra Energy does not have a stock-repurchase program. On February 2, 1998, SoCalGas redeemed all outstanding shares of its 7 3/4% Series Preferred Stock at a cost of $25.09 per share, or $75.3 million including accrued dividends. Dividends Dividends paid on common stock amounted to $325 million in 1998, compared to approximately $300 million in 1997 and 1996. The increase in 1998 is the result of the company's paying dividends on its common stock at the rate previously paid by Enova, which, on an equivalent-share basis, is higher than the rate paid by PE. Dividends are paid quarterly to shareholders. 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 50 percent at year-end 1998, below the 54 percent ratio in 1997. The decrease was primarily due to the repayment of debt. The debt to capitalization ratio increased to 54 percent in 1997 from 50 percent in 1996, primarily due to the issuance of SDG&E's Rate Reduction Bonds. CASH AND CASH EQUIVALENTS Cash and cash equivalents were $424 million at December 31, 1998. This cash is available for investment in energy-related domestic and international projects, and the retirement of debt and other corporate purposes. The company anticipates that cash required in 1999 for capital expenditures and dividend 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 multiyear credit agreements that permit term borrowings of up to $995 million, of which $43 million is outstanding at December 31, 1998. For further discussion, see Note 4 of the notes to Consolidated Financial Statements. RESULTS OF OPERATIONS 1998 Compared to 1997 Net income for 1998 decreased to $294 million, or $1.24 per share of common stock (diluted) in 1998, compared to net income of $432 million, or $1.82 per share of common stock (diluted) in 1997. The decrease in net income is primarily due to the costs associated with the business combinations, and a lower base margin established at SoCalGas in its Performance Based Regulation decision (SoCalGas PBR Decision) which became effective on August 1, 1997, as further described in Note 14 of the notes to Consolidated Financial Statements. Expenses related to the business combinations were $85 million ($0.36 per share) and $20 million ($0.08 per share), aftertax, for 1998 and 1997, respectively. Also contributing to lower net income for 1998 were significant start-up costs at Sempra Energy Solutions and at Sempra Energy Trading as discussed under "Other Operations" below. For the fourth quarter, net income decreased compared to the prior fourth quarter due to PBR and Demand-Side Management awards in the 1997 quarter, electric seasonality effects compared to 1997, and the factors that affected the annual comparison. Book value per share decreased to $12.29 from $12.56, due to common dividends' exceeding the decreased net income in 1998. 1997 Compared to 1996 Net income for 1997 increased to $432 million, or $1.82 per share of common stock (diluted), compared to net income of $427 million, or $1.77 per share (diluted), in 1996. The increase in net income per share is due primarily to the repurchases of common stock, which caused the weighted average number of shares of common stock outstanding to decrease 2 percent in 1997. The increase in net income is primarily due to increased net income from utility operations, partially offset by costs related to the PE/Enova Business Combination and the start-up of unregulated operations. Book value per share increased to $12.56 from $12.21, due to net income's exceeding the combined effect of common dividends and the stock repurchases. UTILITY OPERATIONS To understand the operations and financial results of SoCalGas and SDG&E, it is important to understand the ratemaking procedures that SoCalGas and SDG&E follow. SoCalGas and SDG&E are regulated by the CPUC. It is the responsibility of the CPUC to determine that utilities operate in the best interests of their customers and have the opportunity to earn a reasonable return on investment. In response to utility- industry restructuring, SoCalGas and SDG&E have received approval from the CPUC for PBR. PBR replaces the general rate case (GRC) procedure and certain other regulatory proceedings. Under ratemaking procedures in effect prior to PBR, SoCalGas and SDG&E 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 in Note 14 of the notes to Consolidated Financial Statements. 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 able to buy their electricity through the California Power Exchange (PX) that obtains power from qualifying facilities, nuclear units and, lastly, from the lowest-bidding suppliers. The PX serves as a wholesale power pool, allowing all energy producers to participate competitively. 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 initiated 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. See additional discussion of electric-industry and natural gas-industry restructuring below in "Electric-Industry Restructuring" and "Gas-Industry Restructuring" and in Note 14 of the notes to Consolidated Financial Statements. The table below summarizes the components of utility natural gas and electric volumes and revenues by customer class for 1998, 1997 and 1996. GAS SALES, TRANSPORTATION & EXCHANGE (Dollars in millions, volumes in billion cubic feet) Gas Sales Transportation & Exchange Total ----------------------------------------------------------------------- Throughput Revenue Throughput Revenue Throughput Revenue ----------------------------------------------------------------------- 1998: Residential 304 $2,234 3 $11 307 $2,245 Commercial and Industrial 102 571 329 277 431 848 Utility Electric Generation* 57 9 139 66 196 75 Wholesale 28 7 28 7 ----------------------------------------------------------------------- 463 $2,814 499 $361 962 3,175 Balancing accounts and other (403) --------- Total $2,772 - --------------------------------------------------------------------------------------------- 1997: Residential 268 $1,957 3 $10 271 $1,967 Commercial and Industrial 102 617 332 273 434 890 Utility Electric Generation* 49 14 158 76 207 90 Wholesale 18 12 18 12 ----------------------------------------------------------------------- 419 $2,588 511 $371 930 2,959 Balancing accounts and other 5 --------- Total $2,964 - --------------------------------------------------------------------------------------------- 1996: Residential 264 $1,809 3 $10 267 $1,819 Commercial and Industrial 104 573 314 257 418 830 Utility Electric Generation* 43 9 139 70 182 79 Wholesale 17 10 17 10 ----------------------------------------------------------------------- 411 $2,391 473 $347 884 2,738 Balancing accounts and other (28) --------- Total $2,710 - --------------------------------------------------------------------------------------------- * The portion representing SDG&E's sales for electric generation includes margin only. 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 ----------------------------------------------------------------------- 1998 Compared to 1997 Utility natural gas revenues decreased 6 percent in 1998 primarily due to the lower natural gas margin established in the SoCalGas PBR Decision, a decrease in the average cost of natural gas and a decrease in sales to utility electric-generation customers, partially offset by increased sales to residential customers due to colder weather in 1998. 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 start-up of operations of the PX and Independent System Operator (ISO). These factors were partially offset by a decrease in retail revenue 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 start-up of the PX. The 10-percent rate reduction and PX are described further under "Factors Influencing Future Performance" and in Note 14 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. The company's cost of natural gas distributed decreased 18 percent in 1998, largely due to a decrease in the average cost of natural gas purchased, partially offset by increases in sales volume. 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 54 percent in 1998, primarily due to the recovery of stranded costs via the CTC. The earnings impact of the increase is offset by CTC revenue (see above). Operating expenses increased 16 percent in 1998, primarily due to the higher business-combination costs ($142 million in 1998, compared to $30 million in 1997) and additional operating expenses due to start-up operations in 1998, including the acquisitions of Sempra Energy Trading and CES/Way. 1997 Compared to 1996 Utility natural gas revenues increased 9 percent in 1997 primarily due to an increase in the average unit cost of natural gas, which is recoverable in rates. To a lesser extent, the increase was due to increased throughput to utility electric-generation customers due to increased demand for electricity. The increase was partially offset by an increase in customer purchases of natural gas directly from other suppliers. Utility 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. Utility cost of natural gas distributed increased 22 percent in 1997, largely due to an increase in the average cost of natural gas purchased and increases in sales volume. 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. Operating expenses increased 15 percent in 1997, primarily due to the startup of unregulated operations, partially offset by lower utility operating expenses. The extent of this offset was lessened by reduced costs in 1996 from favorable litigation settlements. FACTORS INFLUENCING FUTURE PERFORMANCE Performance of the company in the near future will depend primarily on the results of SDG&E and SoCalGas. Because of the ratemaking and regulatory process, electric- and natural gas-industry restructuring, and the changing energy marketplace, there are several factors that will influence future financial performance. These factors are summarized below. KN Energy Acquisition On February 22, 1999, the company 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 16 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 14 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 traditional cost-of-service regulation. Through December 31, 1998, SDG&E has recovered transition costs of $500 million for nuclear generation and $200 million for nonnuclear 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. During the 1998-2001 period, recovery of transition costs is limited by a rate cap. See Note 14 of the notes to Consolidated Financial Statements for additional information. Electric-Generation Assets In November 1997, SDG&E 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. This plan included the divestiture of SDG&E's fossil-fueled 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). The March 1998 decision of the CPUC approving the PE/Enova Business Combination required, among other things, the divestiture by SDG&E of its fossil-fueled generation units. On December 11, 1998, SDG&E entered into agreements for the sale of its South Bay Power Plant, Encina Power Plant 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 14 of the notes to Consolidated Financial Statements for additional information. As mentioned above, Sempra Energy Resources and Reliant Energy Power Generation formed a joint venture to build, own and operate a natural gas power plant (El Dorado) in Boulder City, Nevada. The joint venture plans to sell the plant's electricity into the wholesale market, which, in turn, sells to utilities throughout the Western United States. The new plant will employ an advanced combined-cycle gas-turbine technology, enabling it to become one of the most efficient and environmentally friendly power plants in the nation. Its proximity to existing natural gas pipelines and electric transmission lines will allow El Dorado to actively compete in the deregulated electric-generation market. The project, funded equally by the company and Reliant, began in the first quarter of 1998, with an expected operational date set for the fourth quarter of 1999. Electric Rates AB 1890 provides for a 10-percent reduction in rates for residential and small commercial customers effective in January 1998, and provided for the issuance of rate-reduction bonds by an agency of the State of California to enable its 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 SDG&E's residential and small commercial customers via a nonbypassable charge on their electricity bills. In September 1997, SDG&E and the other California IOUs received a favorable ruling by the Internal Revenue Service on the tax treatment of the bond transaction. The ruling states, among other things, that the receipt of the bond proceeds does not result in gross income to SDG&E at the time of issuance, but rather the proceeds are taxable over the life of the bonds. The Securities and Exchange Commission determined that these bonds should be reflected on the utilities' balance sheets as debt, even though the bonds are not secured by, or payable from, utility assets, but rather by the future revenue streams collected from customers. SDG&E formed a subsidiary, SDG&E Funding LLC, to facilitate the issuance of the rate-reduction bonds. In exchange for the bond proceeds, SDG&E sold to SDG&E Funding LLC all of its rights to the revenue streams. Consequently, the revenue streams are not the property of SDG&E and are not available to creditors of SDG&E. AB 1890 also included a rate freeze for all customers. Until the earlier of March 31, 2002, or when transition-cost recovery is complete, SDG&E's average system rate will be held at 9.64 cents per kilowatt-hour, 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. SDG&E'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, 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. 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 14 of the notes to Consolidated Financial Statements. Regulatory Accounting Standards SoCalGas and SDG&E are accounting for the economic effects of regulation on all of their 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 rate-making 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 14 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, which became effective January 1, 1998, 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. 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. As a result, the affiliate-transaction rules will not substantially impact the company's ability to achieve anticipated synergy savings. See Notes 1 and 14 of the notes to Consolidated Financial Statements for additional information. Allowed Rate of Return For 1998, SoCalGas was authorized to earn a rate of return on rate base of 9.49 percent and a rate of return on common equity of 11.6 percent, which is unchanged from 1997. 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 14 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 investment within the amounts authorized to be collected in rates. It is the intent of management to control operating expenses and investments within the amounts authorized to be collected in rates in the PBR decision. The utilities intend to make the efficiency improvements, changes in operations and cost reductions necessary to achieve this objective and earn their authorized rates of return. However, in view of the earnings-sharing mechanism and other elements of the PBR, it is more difficult to exceed authorized returns to the degree experienced in past years. See additional discussion of PBR in Note 14 of the notes to Consolidated Financial Statements. 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 initiated 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 enacted a law prohibiting the CPUC from enacting any natural gas-industry restructuring decision for core customers prior to January 1, 2000. The CPUC continues to study the issue. Noncore Bypass SoCalGas' throughput to enhanced oil recovery (EOR) customers in the Kern County area has decreased significantly since 1992 because of the bypass of SoCalGas' system by competing interstate pipelines. The decrease in revenues from EOR customers has not had a material impact on SoCalGas' earnings. Bypass of other markets also may occur, and SoCalGas is fully at risk for a reduction in non-EOR, noncore volumes due to bypass. However, significant additional bypass would require construction of additional facilities by competing pipelines. SoCalGas is continuing to reduce its costs to maintain cost competitiveness in order to retain transportation customers. Noncore Pricing To respond to bypass, SoCalGas has received authorization from the CPUC for expedited review of long-term gas-transportation service contracts with some noncore customers at lower-than-tariff rates. In addition, the CPUC approved changes in the methodology that eliminates subsidization of core-customer rates by noncore customers. This allocation flexibility, together with negotiating authority, has enabled SoCalGas to better compete with new interstate pipelines for noncore customers. Noncore Throughput SoCalGas' earnings may be adversely impacted if natural gas throughput to its noncore customers varies from estimates adopted by the CPUC in establishing rates. There is a continuing risk that an unfavorable variance in noncore volumes may result from external factors such as weather, electric deregulation, the increased use of hydroelectric power, competing pipeline bypass of SoCalGas' system and a downturn in general economic conditions. In addition, many noncore customers are especially sensitive to the price relationship between natural gas and alternate fuels, as they are capable of readily switching from one fuel to another, subject to air-quality regulations. SoCalGas is at risk for the lost revenue. Through July 31, 1999, any favorable earnings effect of higher revenues resulting from higher throughput to noncore customers has been limited as a result of the Comprehensive Settlement discussed in Note 14 of the notes to Consolidated Financial Statements. Excess Interstate Pipeline Capacity Existing interstate pipeline capacity into California exceeds current demand by over one billion cubic feet (Bcf) per day. This situation has reduced the market value of the capacity well below the Federal Energy Regulatory Commission's (FERC) tariffs. SoCalGas has exercised its step-down option on both the El Paso and Transwestern systems, thereby reducing its firm interstate capacity obligation from 2.25 Bcf per day to 1.45 Bcf per day. FERC-approved settlements have resulted in a reduction in the costs that SoCalGas possibly may have been required to pay for the capacity released back to El Paso and Transwestern that cannot be remarketed. Of the remaining 1.45 Bcf per day of capacity, SoCalGas' core customers use 1.05 Bcf per day at the full FERC tariff rate. The remaining 0.4 Bcf per day of capacity is marketed at significant discounts. Under existing California regulation, unsubscribed capacity costs associated with the remaining 0.4 Bcf per day are recoverable in customer rates. While including the unsubscribed pipeline cost in rates may impact SoCalGas' ability to compete in highly contested markets, SoCalGas does not believe its inclusion will have a significant impact on volumes transported or sold. 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, $5 million in 1997 and $9 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 SDG&E's divestiture of its electric-generating assets is discussed above under "Electric Generation Assets" and in Note 14 of the notes to Consolidated Financial Statements. Hazardous Substances In 1994, the CPUC approved the Hazardous Waste Collaborative, a mechanism which allows SoCalGas, SDG&E 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 Competition Transition Cost (CTC) recovery process described above. During the early 1900s, SDG&E, SoCalGas and their predecessors manufactured gas from coal or oil, the sites of which have often become contaminated with the hazardous residual by-products of the process. SDG&E 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. SoCalGas has identified 42 former manufactured-gas plant sites at which it (together with other utilities of these sites) may have clean up obligations. As of December 31, 1998, 12 of these sites have been remediated and a certificate of closure has been received from the California Environmental Protection Agency for 10 of the sites. A preliminary environmental site assessment has been conducted on 39 of the sites and it is estimated that the cost for the remaining sites is $68 million. In addition, other company subsidiaries have been named as potentially responsible parties (PRPs) in relation to two landfills and three industrial waste disposal sites, and it is estimated that the subsidiaries' share of the costs to remediate such sites is $5 million. Ninety percent of SoCalGas' and SDG&E's costs to clean up the gas plants and to meet their PRP obligations, a total estimated to be $75 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), SDG&E retained limited remediation obligations for contamination existing on these sites upon the closing of the sales. SDG&E'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, SDG&E 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. SDG&E's share of the cost is estimated to be $23 million. The pricing structure contained in the CPUC's decision regarding accelerated recovery of SONGS Units 2 and 3 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 entities. 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. INTERNATIONAL OPERATIONS Sempra Energy International (SEI) was formed in June 1998, merging the international operations of PE and Enova. Prior to the business combination, PE and Enova were already partners in two natural gas distribution projects in Mexico. In addition, PE held an interest in two natural gas utility holding companies in Argentina. SEI develops, operates and invests in energy-infrastructure systems and power-generation facilities outside the United States. SEI has interests in natural gas transmission and distribution projects in Mexico, Argentina and Uruguay and is pursuing projects in other parts of Latin America and in Asia. In March 1998, PE increased its existing investment in two Argentine natural gas utility holding companies (Sodigas Pampeana S.A. and Sodigas Sur S.A.) by purchasing an additional 9-percent interest for $40 million. With this purchase, PE's interest in the holding companies was increased to 21.5 percent. The distribution companies serve 1.2 million customers in central and southern Argentina, respectively, and have a combined sendout of 650 million cubic feet per day. SEI is part of a binational consortium named Distribuidora de Gas Natural de Mexicali, S. de R.L. de C.V. (DGN-Mexicali), a Mexican company that won the first license awarded to a private company to build a natural gas distribution system in Mexico. On August 20, 1997, DGN-Mexicali began to deliver natural gas to customers in Mexicali, Baja California. DGN-Mexicali will invest up to $25 million to provide service to 25,000 customers during the first five years of operation. Proxima Gas, S.A. de C.V. (Proxima), a group of prominent Mexican businesspeople, is the project partner. SEI owns a 60-percent interest in the Mexicali project. SEI also has partnered with Proxima to form Distribuidora de Gas Natural de Chihuahua, S. de R.L. de C.V. (DGN-Chihuahua), which distributes natural gas to the city of Chihuahua, Mexico and surrounding areas. On July 9, 1997, DGN-Chihuahua assumed ownership of a 16-mile transmission pipeline serving 20 industrial customers. DGN-Chihuahua will invest nearly $50 million to provide service to 50,000 customers in the first five years of operation. SEI owns a 95-percent interest in DGN-Chihuahua. On August 27, 1998, SEI was awarded a 10-year agreement by the Mexican Federal Electric Commission to provide natural gas for the Presidente Juarez power plant in Rosarito, Baja California. The contract includes provisions for delivery of up to 300 million cubic feet per day of natural gas transportation services in the United States and construction of a 23-mile pipeline from the U.S.- Mexico border to the plant. This pipeline will also serve other customers in the region. In today's dollars, future revenues under the contract could approach $1 billion. In May 1998, PE was awarded a concession by the government of Uruguay to build a natural gas and propane distribution system to serve most of the country, excluding Montevideo. SEI is currently in discussions with regards to the terms of the concession agreement with the Uruguayan government. The net losses for international operations were $4 million and $9 million, aftertax, for 1998 and 1997, respectively. OTHER OPERATIONS Sempra Energy Trading (SET), a leading natural gas power marketing firm headquartered in Stamford, Connecticut, was jointly acquired by PE and Enova on December 31, 1997. For the year ended December 31, 1998, SET recorded aftertax income of $1 million from its operations and a net loss of $13 million after amortization of costs associated with the acquisition. Additional information concerning SET is provided in Note 10 of the notes to Consolidated Financial Statements. Sempra Energy Solutions (Solutions), formed in 1997 as a joint venture of PE and Enova, incorporates several existing unregulated businesses from each of PE and Enova. It is pursuing a variety of opportunities, including buying and selling natural gas for large users, integrated energy-management services targeted at large governmental and commercial facilities, and consumer-market products and services such as earthquake shutoff valves. CES/Way International, Inc. (CES/Way), which was acquired by Solutions in January 1998, provides energy-efficiency services including energy audits, engineering design, project management, construction, financing and contract maintenance. Solutions' operating losses were $27 million and $14 million, aftertax, for the years ended December 31, 1998, and 1997, respectively. The losses are primarily due to startup costs. OTHER INCOME, INTEREST EXPENSE AND INCOME TAXES Other Income Other income, which primarily consists of interest income from short-term investments and regulatory-balancing accounts, decreased in 1998 to $44 million from $58 million in 1997. The decrease was a result of lower interest income from short-term investments. The increase to $58 million from $28 million in 1996 was due to higher interest from short-term investments during much of 1997. Interest Expense Interest expense for 1998 increased slightly to $207 million from $206 million in 1997. Interest expense for 1997 increased to $206 million from $200 million in 1996, as a result of a higher long- term debt balance. Income Taxes Income tax expense for 1998 was $138 million, less than the $301 million for 1997. The effective income tax rate was 32 percent for 1998 and 41 percent for 1997. The decrease in income tax expense is primarily due to the decrease in pretax income, combined with an increase in affordable-housing tax credits. 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. The company also uses and trades derivative financial instruments in its energy trading and marketing activities. 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. Sempra Energy Trading derives a substantial portion of its revenue from risk management and trading activities in natural gas, petroleum and electricity. Profits are earned as SET acts as a dealer in structuring and executing transactions that assist its customers in managing their energy-price risk. In addition, SET may, on a limited basis, take positions in energy markets based on the expectation of future market conditions. These positions include options, forwards, futures and swaps. See Note 10 of the notes to Consolidated Financial Statements and the following "Market Risk Management Activities" section for additional information regarding SET's use of derivative financial instruments. The company's regulated operations periodically enter 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, the notional amount of swap transactions associated with the regulated operations totaled $45 million. See Note 5 of the notes to Consolidated Financial Statements for further information regarding these swap transactions. The company's regulated operations use energy derivatives to manage natural gas price risk associated with servicing their load requirements. In addition, they make limited use of natural gas derivatives for trading purposes. These instruments include forward contracts, futures, swaps, options and other contracts, with maturities ranging from 30 days to 12 months. In the case of both price-risk management and trading activities, the use of derivative financial instruments by the company's regulated operations is subject to certain limitations imposed by established company policy and regulatory requirements. See Note 10 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's regulated operations. 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 equity and energy. The company has adopted corporate-wide policies governing its market- risk management and trading activities. An Energy Risk Management Oversight Committee, consisting of senior corporate officers, oversees company-wide energy-price risk-management and trading activities to ensure compliance with the company's stated energy risk management and trading policies. In addition, all affiliates have groups that monitor and control energy-price risk management and trading activities independently from the groups responsible for creating or actively managing these risks. 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 utility 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. A portion of the company's borrowings are denominated in foreign currencies, which expose the company to market risk associated with exchange-rate movements. The company's policy generally is to hedge major foreign-currency cash exposures through swap transactions. These contracts are entered into with major international banks, thereby minimizing the risk of credit loss. The VaR on the company's fixed rate long term debt is estimated at approximately $312 million as of December 31, 1998, assuming a one-year holding period. The VaR attributable to currency exchange rates nets to zero as a result of a currency swap that is directly matched to the company's Swiss Franc debt obligation, its only non-dollar-denominated debt. 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's regulated and unregulated affiliates are 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 of each affiliate. Sempra Energy Trading Sempra Energy Trading derives a substantial portion of its revenue from risk management and trading activities in natural gas, petroleum and electricity. As such, SET is exposed to price volatility in the domestic and international natural gas, petroleum and electricity markets. SET conducts these activities within a structured and disciplined risk management and control framework that is based on clearly communicated policies and procedures, position limits, active and ongoing management monitoring and oversight, clearly defined roles and responsibilities, and daily risk measurement and reporting. Market risk of SET's portfolio is measured using a variety of methods, including VaR. SET computes the VaR of its portfolio based on a three-day holding period. As of December 31, 1998, the diversified VaR of SET's portfolio was $5.3 million. SDG&E SDG&E 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 and trading framework. As of December 31, 1998, the total VaR of SDG&E'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 14 of the notes to Consolidated Financial Statements and the discussion under "Factors Influencing Future Performance" for further information regarding the electricity rate cap. SoCalGas SoCalGas is exposed to market risk on its natural gas purchase, sale and storage activities whenever natural gas prices fall outside the Gas Cost Incentive Mechanism tolerance band. SoCalGas manages this risk within the parameters of the company's market risk management and trading framework. As of December 31, 1998, the total VaR of SoCalGas' natural gas positions was not material. 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 issues impact 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 company's overall Year 2000 readiness effort. The company has established a central Year 2000 Program Office, which reports to the company's 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. The company 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. The company 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. The company'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 the company's 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 the company's schedule to change. Costs to Address the Company's Year 2000 Issues Sempra Energy's budget for the Year 2000 program is $48 million, of which $38 million has been spent. As the company continues to assess its systems and as the remediation and testing efforts progress, cost estimates may change. The company's Year 2000 readiness effort is being funded entirely by operating cash flows. The Risks of the Company's Year 2000 Issues Based upon its current assessment and testing of the Year 2000 issue, the company believes the reasonably likely worst-case Year 2000 scenarios would have the following impacts upon Sempra Energy and its operations. With respect to the company's ability to provide energy to its domestic utility customers, the company believes that the reasonably likely worst-case scenario is for small, localized interruptions of natural gas or electrical service which are restored in a timeframe 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. The company 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 interruptions related to Year 2000 issues are being incorporated in the company's 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. The company 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 the company's operations due to Year 2000 issues. NEW ACCOUNTING STANDARDS In April 1998, the American Institute of Certified Public Accountants issued Statement of Position 98-5 "Reporting on the Costs of Start-up Activities". This statement is effective for 1999, but is not expected to have a significant effect on the company's Consolidated Financial Statements. 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 Annual 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. STATEMENT OF MANAGEMENT RESPONSIBILITY FOR CONSOLIDATED FINANCIAL STATEMENTS The consolidated financial statements have been prepared by management in accordance with generally accepted accounting principles. The integrity and objectivity of these financial statements and the other financial information in the Annual Report, including the estimates and judgments on which they are based, are the responsibility of management. The financial statements have been audited by Deloitte & Touche LLP, independent certified public accountants appointed by the Board of Directors. Their report is shown below. Management has made available to Deloitte & Touche LLP all of the company's financial records and related data, as well as the minutes of shareholders' and directors' meetings. Management maintains a system of internal accounting control which it believes is adequate to provide reasonable, but not absolute, assurance that assets are properly safeguarded and accounted for, that transactions are executed in accordance with management's authorization and are properly recorded and reported, and for the prevention and detection of fraudulent financial reporting. The concept of reasonable assurance recognizes that the cost of a system of internal controls should not exceed the benefits derived and that management makes estimates and judgments of these cost/benefit factors. Management monitors the system of internal control for compliance through its own review and a strong internal auditing program which also independently assesses the effectiveness of the internal controls. In establishing and maintaining internal controls, the company must exercise judgment in determining whether the benefits derived justify the costs of such controls. Management acknowledges its responsibility to provide financial information (both audited and unaudited) that is representative of the company's operations, reliable on a consistent basis, and relevant for a meaningful financial assessment of the company. Management believes that the control process enables it to meet this responsibility. Management also recognizes its responsibility for fostering a strong ethical climate so that the company's affairs are conducted according to the highest standards of personal and corporate conduct. This responsibility is characterized and reflected in the company's code of corporate conduct, which is publicized throughout the company. The company maintains a systematic program to assess compliance with this policy. The Board of Directors has an Audit Committee composed solely of directors who are not officers or employees. The Committee recommends for approval by the full Board the appointment of the independent auditors. The Committee meets regularly with management, with the company's internal auditors and with the independent auditors. The independent auditors and the internal auditors periodically meet alone with the Audit Committee and have free access to the Audit Committee at any time. /s/ Neal E. Schmale Neal E. Schmale Executive Vice President and Chief Financial Officer /s/ Frank H. Ault Frank H. Ault Vice President and Controller INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders of Sempra Energy: We have audited the accompanying consolidated balance sheets of Sempra Energy and subsidiaries (the "company") 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 Sempra Energy and subsidiaries 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 16 as to which the date is February 22, 1999 SEMPRA ENERGY Statements of Consolidated Income Years Ended December 31, ------------------------------- (Dollars in millions, except per share amounts) 1998 1997 1996 - ----------------------------------------------------------------------------------- Revenues and Other Income Utility revenues: Natural gas $ 2,772 $ 2,964 $ 2,710 Electric 1,865 1,769 1,591 PX/ISO power 500 -- -- Other operating revenues 344 336 195 Other income 44 58 28 -------- -------- -------- Total 5,525 5,127 4,524 -------- -------- -------- Expenses Cost of natural gas distributed 954 1,168 958 PX/ISO power 468 -- -- Purchased power 292 441 311 Electric fuel 177 164 134 Operating expenses 1,872 1,615 1,405 Depreciation and amortization 929 604 587 Franchise payments and other taxes 182 178 180 Preferred dividends of subsidiaries 12 18 22 -------- -------- -------- Total 4,886 4,188 3,597 -------- -------- -------- Income Before Interest and Income Taxes 639 939 927 Interest 207 206 200 -------- -------- -------- Income Before Income Taxes 432 733 727 Income taxes 138 301 300 -------- -------- -------- Net Income $ 294 $ 432 $ 427 ======== ======== ======== Net Income Per Share of Common Stock (Basic) $ 1.24 $ 1.83 $ 1.77 ======== ======== ======== Net Income Per Share of Common Stock (Diluted) $ 1.24 $ 1.82 $ 1.77 ======== ======== ======== Common Dividends Declared Per Share $ 1.56 $ 1.27 $ 1.24 ======== ======== ======== See notes to Consolidated Financial Statements. SEMPRA ENERGY Consolidated Balance Sheets December 31, ---------------- (Dollars in millions) 1998 1997 - -------------------------------------------------------------------- Assets Current assets: Cash and cash equivalents $ 424 $ 814 Accounts receivable - trade 586 633 Accounts and notes receivable - other 159 202 Deferred income taxes 93 15 Energy trading assets 906 587 Inventories 151 111 Regulatory balancing accounts - net -- 297 Other 139 102 ------- ------- Total current assets 2,458 2,761 ------- ------- Investments and other assets: Regulatory assets 980 1,186 Nuclear-decommissioning trusts 494 399 Investments 548 429 Other assets 535 439 ------- ------- Total investments and other assets 2,557 2,453 ------- ------- Property, plant and equipment: Property, plant and equipment 11,235 10,902 Less accumulated depreciation and amortization (5,794) (5,360) ------- ------- Total property, plant and equipment - net 5,441 5,542 ------- ------- Total assets $ 10,456 $ 10,756 ======= ======= See notes to Consolidated Financial Statements. SEMPRA ENERGY Consolidated Balance Sheets December 31, ----------------- (Dollars in millions) 1998 1997 - ------------------------------------------------------------------ Liabilities Current liabilities: Short-term debt $ 43 $ 354 Accounts payable - trade 702 625 Accrued income taxes 27 5 Energy trading liabilities 805 557 Dividends and interest payable 168 121 Regulatory balancing accounts - net 120 -- Long-term debt due within one year 330 270 Other 271 279 ------- ------- Total current liabilities 2,466 2,211 ------- ------- Long-term debt: Long-term debt 2,795 3,045 Debt of Employee Stock Ownership Plan -- 130 ------- ------- Total long-term debt 2,795 3,175 ------- ------- Deferred credits and other liabilities: Customer advances for construction 72 72 Post-retirement benefits other than pensions 240 248 Deferred income taxes 634 741 Deferred investment tax credits 147 155 Deferred credits and other liabilities 985 916 ------- ------- Total deferred credits and other liabilities 2,078 2,132 ------- ------- Preferred stock of subsidiaries 204 279 ------- ------- Commitments and contingent liabilities (Note 13) Shareholders' Equity Common stock 1,883 1,849 Retained earnings 1,075 1,157 Less deferred compensation relating to Employee Stock Ownership Plan (45) (47) ------- ------- Total shareholders' equity 2,913 2,959 ------- ------- Total liabilities and shareholders' equity $ 10,456 $ 10,756 ======= ======= See notes to Consolidated Financial Statements. SEMPRA ENERGY Statements of Consolidated Cash Flows Years Ended December 31 --------------------------------- (Dollars in millions) 1998 1997 1996 - ------------------------------------------------------------------------------------------ CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 294 $ 432 $ 427 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 929 604 587 Deferred income taxes and investment tax credits (199) (16) 26 Other - net (180) 62 56 Net changes in other working capital components 479 (164) 68 ---------- --------- --------- Net cash provided by operating activities 1,323 918 1,164 ---------- --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES Expenditures for property, plant and equipment (438) (397) (413) Acquisitions of subsidiaries (191) (206) (50) Contributions to decommissioning trusts (22) (22) (22) Other (28) 23 (29) --------- ----------- ---------- Net cash used in investing activities (679) (602) (514) --------- ----------- ---------- CASH FLOWS FROM FINANCING ACTIVITIES Common stock dividends (325) (301) (300) Sale of common stock 34 17 8 Repurchase of common stock (1) (122) (24) Redemption of preferred stock (75) -- (225) Issuances of other long-term debt 75 140 304 Issuance of rate-reduction bonds -- 658 -- Payment on long-term debt (431) (416) (459) Increase (decrease) in short-term debt - net (311) 92 29 --------- ----------- ---------- Net cash provided by (used in) financing activities (1,034) 68 (667) --------- ----------- ---------- Increase (Decrease) in Cash and Cash Equivalents (390) 384 (17) Cash and Cash Equivalents, January 1 814 430 447 --------- ----------- ---------- Cash and Cash Equivalents, December 31 $ 424 $ 814 $ 430 ========= =========== ========== See notes to Consolidated Financial Statements. SEMPRA ENERGY Statements of Consolidated Cash Flows Years Ended December 31 --------------------------------- (Dollars in millions) 1998 1997 1996 - ------------------------------------------------------------------------------------------ CHANGES IN OTHER WORKING CAPITAL COMPONENTS (Excluding cash and cash equivalents, short-term debt and long-term debt due within one year) Accounts and notes receivable $ 90 $ (129) $ (58) Net trading assets (71) -- -- Inventories (40) (2) 32 Regulatory balancing accounts 417 48 9 Other current assets (26) 41 40 Accounts payable and other current liabilities 109 (122) 45 -------- -------- -------- Net change in other working capital components $ 479 $ (164) $ 68 ======== ======== ======== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Cash paid during the year for: Interest (net of amounts capitalized) $ 211 $ 193 $ 205 Income taxes (net of refunds) $ 366 $ 274 $ 268 SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND FINANCING ACTIVITIES Acquisition of Sempra Energy Trading: Assets acquired $ -- $ 609 $ -- Cash paid -- (225) -- ---------- ----------- --------- Liabilities assumed $ -- $ 384 $ -- ========== =========== ========= Liabilities assumed for real estate investments $ 36 $ 126 $ 97 ========== =========== ========= Nonutility electric generation assets sold: Book value of assets sold $ -- $ 77 $ -- Cash received -- (20) -- Loss on sale -- (6) -- ---------- ----------- --------- Note receivable obtained $ -- $ 51 $ -- ========== =========== ========= See notes to Consolidated Financial Statements. SEMPRA ENERGY STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY For the years ended December 31, 1998, 1997, 1996 (Dollars in millions) Deferred Compensation Total Common Retained Relating Shareholders' Stock Earnings to ESOP Equity - ------------------------------------------------------------------------------------ Balance at December 31, 1995 $ 1,968 $ 899 $ (52) $ 2,815 Net income 427 427 Common stock dividends declared (300) (300) Sale of common stock 8 8 Repurchase of common stock (24) (24) Common stock released from ESOP 3 3 Long-term incentive plan 1 1 - ------------------------------------------------------------------------------------ Balance at December 31, 1996 1,953 1,026 (49) 2,930 Net income 432 432 Common stock dividends declared (301) (301) Sale of common stock 17 17 Repurchase of common stock (122) (122) Common stock released from ESOP 2 2 Long-term incentive plan 1 1 - ------------------------------------------------------------------------------------ Balance at December 31, 1997 1,849 1,157 (47) 2,959 Net income 294 294 Common stock dividends declared (376) (376) Sale of common stock 34 34 Repurchase of common stock (1) (1) Common stock released from ESOP 2 2 Long-term incentive plan 1 1 - ------------------------------------------------------------------------------------ Balance at December 31, 1998 $ 1,883 $1,075 $ (45) $ 2,913 ==================================================================================== See notes to Consolidated Financial Statements. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1 BUSINESS COMBINATION On June 26, 1998, Enova Corporation (Enova) and Pacific Enterprises (PE) combined into a new company named Sempra Energy (the company). 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 Enova's principal subsidiary, San Diego Gas & Electric Company (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. 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 14. 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 electric-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. The Consolidated Financial Statements are those of the company and its subsidiaries and give effect to the business combination using the pooling-of-interests method and, therefore, are presented as if the companies were combined during all periods included therein. The per-share data shown on the Statements Of Consolidated Income reflect the conversion of Enova common stock and of PE common stock into Sempra Energy common stock as described above. All significant intercompany transactions, including SoCalGas' sales of natural gas transportation and storage to SDG&E, have been eliminated. These sales amounted to approximately $60 million in each of the years presented. The results of operations for PE and Enova as reported as separate companies through June 30, 1998, are as follows: - --------------------------------------------------------------- Six months ended June 30, (Dollars in millions) 1998 1997 1996 - --------------------------------------------------------------- PACIFIC ENTERPRISES Revenue and Other Income $1,263 $2,777 $2,588 Net Income $ 50 $ 180 $ 196 ENOVA Revenue and Other Income $1,299 $2,224 $1,996 Net Income $ 68 $ 252 $ 231 - --------------------------------------------------------------- 2 SIGNIFICANT ACCOUNTING POLICIES Property, Plant and Equipment This primarily represents the buildings, equipment and other facilities used by SDG&E and SoCalGas 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 14. Utility plant balances by major functional categories at December 31, 1998, are: natural gas operations $7.0 billion, electric distribution $2.4 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 $3.5 billion and $2.2 billion, respectively, and at December 31, 1997, were $3.3 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 4.32, 4.31, 4.35, 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 14 for additional discussion of generation facilities and industry restructuring. Inventories Included in inventories at December 31, 1998, are $61 million of utility materials and supplies ($56 million in 1997), and $78 million of natural gas and fuel oil ($47 million in 1997). Materials and supplies are generally valued at the lower of average cost or market; fuel oil and natural gas are valued by the last-in first-out method. Trading Instruments Trading assets and trading liabilities are recorded on a trade-date basis at fair value and include option premiums paid and received, and unrealized gains and losses from exchange-traded futures and options, over the counter (OTC) swaps, forwards, and options. Unrealized gains and losses on OTC transactions reflect amounts which would be received from or paid to a third party upon settlement of the contracts. Unrealized gains and losses on OTC transactions are reported separately as assets and liabilities unless a legal right of setoff exists under a master netting arrangement enforceable by law. Revenues are recognized on a trade- date basis and include realized gains and losses, and the net change in unrealized gains and losses. Futures and exchange-traded option transactions are recorded as contractual commitments on a trade-date basis and are carried at fair value based on closing exchange quotations. Commodity swaps and forward transactions are accounted for as contractual commitments on a trade-date basis and are carried at fair value derived from dealer quotations and underlying commodity-exchange quotations. OTC options are carried at fair value based on the use of valuation models that utilize, among other things, current interest, commodity and volatility rates, as applicable. For long- dated forward transactions, where there are no dealer or exchange quotations, fair values are derived using internally developed valuation methodologies based on available market information. Where market rates are not quoted, current interest, commodity and volatility rates are estimated by reference to current market levels. Given the nature, size and timing of transactions, estimated values may differ from realized values. Changes in the fair value are recorded currently in income. Effects of Regulation SDG&E and SoCalGas accounting policies conform with generally accepted accounting principles for regulated enterprises and reflect the policies of the CPUC and the FERC. The company's interstate natural gas transmission subsidiary follows accounting policies authorized by the FERC. SDG&E and SoCalGas have been preparing their 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 14, 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 14. Revenues and Regulatory Balancing Accounts Revenues from utility customers consist of deliveries to customers and the changes in regulatory balancing accounts. The amounts included in regulatory balancing accounts at December 31, 1998, represent a $129 million net payable for SoCalGas combined with a $9 million net receivable for SDG&E. The corresponding amounts at December 31, 1997 were $355 million net receivable and $58 million net payable for SoCalGas and SDG&E, respectively. 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 14. Regulatory Assets Regulatory assets include San Onofre Nuclear Generating Station (SONGS), unrecovered premium on early retirement of debt, post- retirement benefit costs, deferred income taxes recoverable in rates and other regulatory-related expenditures that the utilities expect to recover in future rates. See Note 14 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 SDG&E's SONGS Unit 1, which was permanently shut down in 1992. Additional information on SONGS Unit 1 decommissioning costs is included in Note 6. 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. Quasi-Reorganization In 1993, PE completed a strategic plan to refocus on its natural gas utility and related businesses. The strategy included the divestiture of its merchandising operations and all of its oil and gas exploration and production business. In connection with the divestitures, PE effected a quasi-reorganization for financial reporting purposes, effective December 31, 1992. Certain of the liabilities established in connection with discontinued operations and the quasi-reorganization will be resolved in future years. Management believes the provisions previously established for these matters are adequate at December 31, 1998. 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 Cash equivalents 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 from the predecessor companies' classifications to conform to the format of these financial statements. 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. 3 ACQUISITIONS AND JOINT VENTURES Sempra Energy Trading In December 1997, PE and Enova jointly acquired Sempra Energy Trading (SET) for $225 million. SET is a wholesale-energy trading company based in Stamford, Connecticut. It participates in marketing and trading physical and financial energy products, including natural gas, power, crude oil and associated commodities. In July 1998, SET purchased CNG Energy Services Corporation, a subsidiary of Pittsburgh-based Consolidated Natural Gas Company, for $36 million. The acquisition expands SET's business volume by adding large, commodity-trading contracts with local distribution companies, municipalities and major industrial corporations in the eastern United States. Sempra Energy Resources In December 1997, Sempra Energy Resources (SER) in partnership with Reliant Energy Power Generation, formed El Dorado Energy. In April 1998, El Dorado Energy began construction on a 480-megawatt power plant near Boulder City, Nevada. SER invested $2.3 million in 1997 and $19.7 million in 1998 on this $263-million project. In October 1998, El Dorado Energy obtained a $158-million senior secured credit facility, which entails both construction and 15-year term financing for the project. This financing represents approximately 60 percent of estimated total project costs. Sempra Energy Utility Ventures In September 1997, Sempra Energy Utility Ventures (SEUV) formed a joint venture with Bangor Hydro to build, own and operate a $40- million natural gas distribution system in Bangor, Maine. Construction began in June 1998. The new Bangor Gas Company expects to begin deliveries in the fourth quarter of 1999. In December 1997, SEUV formed Frontier Energy with Frontier Utilities of North Carolina to build and operate a $55-million natural gas distribution system in North Carolina. Natural gas delivery began in December 1998. Subsequent to December 31, 1998, SEUV purchased Frontier Utilities' interest and acquired 100 percent ownership of the system. Sempra Energy Solutions In January 1998, Sempra Energy Solutions completed the acquisition of CES/Way International, a national leader in energy-service performance contracting headquartered in Houston, Texas. CES/Way provides energy-efficiency services, including energy audits, engineering design, project management, construction, financing and contract maintenance. In May 1997, Sempra Energy Solutions entered into a joint venture agreement with Conectiv Thermal Systems, Inc. (formerly Atlantic Thermal System, Inc.) to form Atlantic-Pacific Las Vegas, with each receiving a 50-percent interest. Atlantic-Pacific Las Vegas provides integrated energy-management services to commercial and industrial customers, including the construction of facilities. In May 1997, Atlantic-Pacific Las Vegas entered into an energy- services agreement with three other parties to finance, own, operate and maintain an integrated thermal-energy production facility at the site of the future Venetian Casino Resort in Las Vegas. Construction costs incurred to date are $48 million. A second joint venture agreement was entered into with Conectiv Thermal Systems to form Atlantic-Pacific Glendale in August 1997, with each receiving a 50-percent interest. Atlantic- Pacific Glendale entered into an integrated energy-management services agreement with Dreamworks Animation, LLC to develop, manage and finance the construction and operation of a central chiller plant, emergency power generators and chilled-water distribution and circulation system at Dreamworks' Glendale facilities. The cost of the project, completed in May 1998, was $7 million. International Natural Gas Projects Sempra Energy International (SEI) is a wholly owned subsidiary of Sempra Energy. Sempra Energy International and Proxima Gas S.A. de C.V., partners in the Mexican companies Distribuidora de Gas Natural (DGN) de Mexicali and Distribuidora de Gas Natural de Chihuahua, are the licensees to build and operate natural gas distribution systems in Mexicali and Chihuahua. DGN-Mexicali will invest up to $25 million during the first five years of the 30-year license period. DGN-Chihuahua will invest up to $50 million over the first five years of operation. DGN-Mexicali and DGN-Chihuahua assumed ownership of natural gas distribution facilities during the third quarter of 1997. SEI owns interests of 60 and 95 percent in the DGN-Mexicali and DGN-Chihuahua projects, respectively. In August 1998, SEI was awarded a 10-year agreement by the Mexican Federal Electric Commission to provide a complete energy-supply package for a power plant in Rosarito, Baja California. The contract includes provisions for delivery of up to 300 million cubic feet per day of natural gas, transportation services in the U.S. and construction of a 23-mile pipeline from the U.S.-Mexico border to the plant. The pipeline is expected to cost approximately $35 million and take a year to build. Delivery of natural gas is expected to commence in December 1999. SEI also has interests in Argentina and Uruguay. In March 1998, SEI increased its existing investment in two Argentine natural gas utility holding companies (Sodigas Pampeana S.A. and Sodigas Sur S.A.) from 12.5 percent to 21.5 percent by purchasing an additional interest for $40 million. 4 SHORT-TERM BORROWINGS PE has a $300 million multi-year credit agreement. SoCalGas has an additional $400 million multi-year credit agreement. These agreements expire in 2001 and bear interest at various rates based on market rates and the companies' credit ratings. SoCalGas' lines of credit are available to support commercial paper. At December 31, 1998, PE had $43 million of bank loans under the credit agreement outstanding, due and paid in January 1999. SoCalGas' bank line of credit was unused. At December 31, 1997, both bank lines of credit were unused. 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. At December 31, 1998, there were no commercial-paper obligations outstanding. At December 31, 1997, SoCalGas had $354 million of commercial-paper obligations outstanding, of which approximately $94 million related to the restructuring costs associated with certain long-term gas-supply contracts under the Comprehensive Settlement. See Note 14 for additional information. 5 LONG-TERM DEBT - -------------------------------------------------------------- December 31, (Dollars in millions) 1998 1997 - -------------------------------------------------------------- Long-Term Debt First mortgage bonds 5.25% March 1, 1998 $ _ $ 100 7.625% June 15, 2002 28 80 6.875% August 15, 2002 100 100 5.75% November 15, 2003 100 100 6.8% June 1, 2015 14 14 5.9% June 1, 2018 71 71 5.9% September 1, 2018 93 93 6.1% and 6.4% September 1, 2018 and 2019 118 118 9.625% April 15, 2020 10 54 Variable rates September 1, 2020 58 75 5.85% June 1, 2021 60 60 8.75% October 1, 2021 150 150 8.5% April 1, 2022 10 44 7.375% March 1, 2023 100 100 7.5% June 15, 2023 125 125 6.875% November 1, 2025 175 175 Various rates December 1, 2027 250 250 ---------------------- Total 1,462 1,709 Rate-reduction bonds 592 658 Debt incurred to acquire limited partnerships, secured by real estate, at 6.8% to 9.0%, payable annually through 2008 305 313 Various unsecured bonds at 4.15% to 10% from 1998 to 2006 453 296 Various unsecured bonds at 5.9% or at variable rates (4.3% to 5.0% at December 31, 1998) from 2014 to 2023 254 254 Capitalized leases 76 106 ---------------------- Total 3,142 3,336 ---------------------- Less: Current portion of long-term debt 330 270 Unamortized discount on long-term debt 17 21 ---------------------- 347 291 ---------------------- Total $ 2,795 $ 3,045 - -------------------------------------------------------------- Excluding capital leases, which are described in Note 13, maturities of long-term debt, including PE's Employees Stock Ownership Plan, are $271 million in 1999, $96 million in 2000, $186 million in 2001, $193 million in 2002 and $241 million in 2003. SDG&E and SoCalGas have CPUC authorization to issue an additional $752 million in long-term debt. Although holders of variable-rate bonds may elect to redeem them prior to scheduled maturity, for purposes of determining the maturities listed above, it is assumed the bonds will be held to maturity. First-Mortgage Bonds First-mortgage bonds are secured by a lien on substantially all utility plant. In addition, certain non-utility subsidiary assets are pledged as collateral for SoCalGas' first-mortgage bonds. SDG&E and SoCalGas may issue additional first-mortgage bonds upon compliance with the provisions of their bond indentures, which provide for, among other things, the issuance of additional first- mortgage bonds ($1.5 billion as of December 31, 1998). During 1998, the company retired $247 million of first- mortgage bonds, of which $147 million was retired prior to scheduled maturity. Certain first-mortgage bonds may be called at SDG&E's or SoCalGas' option. SoCalGas has no variable-rate bonds. SDG&E has $188 million of bonds with variable interest-rate provisions that are callable at various dates within one year. Of the company's remaining callable bonds, $10 million are callable in the year 2000, $150 million in 2001, $203 million in 2002, and $624 million in 2003. $242 million of the bonds are not callable. 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 14 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. Unsecured Debt Various long-term obligations totaling $707 million are unsecured. During 1998, SoCalGas issued $75 million of unsecured debt in medium-term notes used to finance working capital requirements. Unsecured bonds totaling $124 million have variable-interest-rate provisions. Debt of Employee Stock Ownership Plan (ESOP) and Trust The Trust covers substantially all of the company's former PE employees and is used to fund part of their retirement savings program. It has an ESOP feature and holds approximately 3.1 million shares of the company's common stock. The variable-rate ESOP debt held by the Trust bears interest at a rate necessary to place or remarket the notes at par. The balance of this debt was $130 million at December 31, 1998, and is included in the table above as part of the various unsecured bonds at 4.15 percent to 10 percent. Principal is due on November 30, 1999, and interest is payable monthly. The company is obligated to make contributions to the Trust sufficient to satisfy debt service requirements. As the company makes contributions to the Trust, these contributions, plus any dividends paid on the unallocated shares of the company's common stock held by the Trust, will be used to repay the debt. As dividends are increased or decreased, required contributions are reduced or increased, respectively. Interest on ESOP debt amounted to $6 million each in 1998, 1997 and 1996. Dividends used for debt service amounted to $3 million each in 1998, 1997, and 1996, and are deductible only for federal income tax purposes. Currency 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. 6 FACILITIES UNDER JOINT OWNERSHIP SONGS and the Southwest Powerlink transmission line are owned jointly with other utilities. The company'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 project 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 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 13 and 14. 7 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 6.3 7.1 6.2 State income taxes-net of federal income tax benefit 7.4 6.7 6.2 Tax credits (12.9) (5.7) (4.8) Equipment leasing activities (1.5) (1.1) (1.4) Capitalized expenses not deferred 0.2 (1.4) (2.1) Other-net (2.6) 0.5 2.2 --------------------------- Effective income tax rate 31.9% 41.1% 41.3% - -------------------------------------------------------------- The components of income tax expense are as follows: - -------------------------------------------------------------- (Dollars in millions) 1998 1997 1996 - -------------------------------------------------------------- Current: Federal $278 $236 $183 State 89 63 65 --------------------------- Total current taxes 367 299 248 --------------------------- Deferred: Federal (165) 1 52 State (58) 7 6 --------------------------- Total deferred taxes (223) 8 58 --------------------------- Deferred investment tax credits-net (6) (6) (6) --------------------------- Total income tax expense $138 $301 $300 - -------------------------------------------------------------- Accumulated deferred income taxes at December 31 result from the following: - -------------------------------------------------------------- (Dollars in millions) 1998 1997 - -------------------------------------------------------------- Deferred Tax Liabilities: Differences in financial and tax bases of utility plant $924 $1,063 Regulatory balancing accounts 23 133 Regulatory assets 76 120 Partnership income 27 21 Other 71 53 ------------------ Total deferred tax liabilities 1,121 1,390 ------------------ Deferred Tax Assets: Unamortized investment tax credits 88 89 Comprehensive Settlement (see Note 14) 95 117 Postretirement benefits 76 90 Other deferred liabilities 102 110 Restructuring costs 42 54 Other 177 204 ------------------ Total deferred tax assets 580 664 ------------------ Net deferred income tax liability 541 726 Current portion (net asset) 93 15 ------------------ Non-current portion (net liability) $634 $741 - -------------------------------------------------------------- 8 EMPLOYEE BENEFIT PLANS The information presented below describes the plans of the company and its principal subsidiaries. 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 subsidiaries' plans to those of Sempra Energy. Pension and Other Postretirement Benefits The company sponsors several 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% 7.07% 6.75% 7.02% Expected return on plan assets 8.50% 8.13% 8.50% 7.87% 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 $2,117 $1,981 $ 531 $ 442 Service cost 55 53 13 15 Interest cost 148 144 36 35 Plan participants' contributions _ _ 1 1 Plan amendments 18 _ _ _ Actuarial (gain) loss (44) 54 _ 57 Special termination benefits 63 13 3 2 Gross benefits paid (277) (128) (21) (21) ---------------------------------------------- Net benefit obligation at December 31 2,080 2,117 563 531 ---------------------------------------------- Change in Plan Assets: Fair value of plan assets at January 1 2,653 2,373 363 286 Actual return on plan assets 407 406 64 59 Employer contributions 13 2 36 38 Plan participants' contributions _ _ 1 1 Gross benefits paid (277) (128) (21) (21) ---------------------------------------------- Fair value of plan assets at December 31 2,796 2,653 443 363 ---------------------------------------------- Funded status at December 31 716 536 (120) (168) Unrecognized net actuarial gain (926) (733) (107) (66) Unrecognized prior service cost 73 61 (13) (14) Unrecognized net transition obligation 3 4 _ _ ---------------------------------------------- Net liability at December 31 (3) $ (134) $ (132) $(240) $(248) - ------------------------------------------------------------------------------------- (1) Decreasing to ultimate trend of 6.50% in 2004. (2) Decreasing to ultimate trend of 6.50% in 1998. (3) Approximates amounts recognized in the Consolidated Balance Sheets at December 31. 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 $55 $53 $58 $13 $15 $18 Interest cost 148 144 141 36 35 36 Expected return on assets (196) (178) (161) (24) (22) (19) Amortization of: Transition obligation 1 1 1 2 2 2 Prior service cost 6 5 5 (1) (1) (1) Actuarial (gain) loss (23) (18) (4) _ 1 1 Special termination benefit 63 13 _ 3 2 _ Settlement credit (30) _ _ _ _ _ Regulatory adjustment _ _ (12) 9 12 12 ----------------------------------------------------- Total net periodic benefit cost $24 $20 $28 $38 $44 $49 - ------------------------------------------------------------------------------------- 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 $11 $(10) Effect on the health care component of the accumulated postretirement benefit obligation $72 $(65) - ------------------------------------------------------------------ The projected benefit obligation and accumulated benefit obligation were $55 million and $45 million, respectively, as of December 31, 1998, and $53 million and $44 million, as of December 31, 1997. There were no pension plans with accumulated benefit obligations in excess of plan assets for 1998 or 1997. Other postretirement benefits include medical benefits for retirees and their spouses (and Medicare Part B reimbursement for certain retirees) and retiree life insurance. Savings Plans Sempra Energy and its subsidiaries offer savings plans, administered by plan trustees, to all eligible employees. Eligibility to participate in the various employer plans ranges from one month to one year of completed service. Employees may contribute, subject to plan provisions, from 1 percent to 15 percent of their regular earnings. Employer contributions, after one year of completed service, are made in shares of company common stock. Employer contribution methods vary by plan, but generally the contribution is equal to 50 percent of the first 6 percent of eligible base salary contributed by employees. During 1998, the SDG&E plan contribution was age-based for represented employees. The employee's contributions, at the direction of the employees, are primarily invested in company stock, mutual funds or guaranteed investment contracts. Employer contributions for the Sempra and SoCalGas plans are partially funded by the Pacific Enterprises Employee Stock Ownership Plan and Trust. Annual expense for the savings plans was $14 million in 1998, $11 million in 1997 and $10 million in 1996. Employee Stock Ownership Plan The Pacific Enterprises Employee Stock Ownership Plan and Trust (Trust) covers substantially all employees of PE and SoCalGas and is used to partially fund their retirement savings plan programs. All contributions to the Trust are made by the company, and there are no contributions made by the participants. As the company makes contributions to the ESOP, the ESOP debt service is paid and shares are released in proportion to the total expected debt service. Compensation expense is charged and equity is credited for the market value of the shares released. Income-tax deductions are allowed based on the cost of the shares. Dividends on unallocated shares are used to pay debt service and are charged against liabilities. The Trust held 3.1 million and 3.3 million shares of company common stock, with fair values of $77.9 million and $80.3 million, at December 31, 1998, and 1997, respectively. 9 STOCK-BASED COMPENSATION Sempra Energy has stock-based compensation plans that align employee and shareholder objectives related to the long-term growth of the company. The company's 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. 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, the company adopted its disclosure-only requirements and continues to account for stock- based compensation in accordance with the provisions of accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees." In 1998, 102,640 shares of Sempra Energy common stock were awarded to officers. Under the predecessor plan, in each of the last 10 years, Enova awarded between 49,000 and 75,000 shares to key executives. These awards are subject to forfeiture over four years if certain corporate goals are not met. Holders of this stock have voting rights and receive dividends prior to the time the restrictions lapse if, and to the extent, dividends are paid on Sempra Energy common stock. Compensation expense for the issuance of these restricted shares was approximately $2 million in 1998, $1 million in 1997 and $1 million in 1996. In 1998, Sempra Energy granted 3,425,800 stock options. The option price is equal to the market price of common stock at the date of grant. The grants, which vest over a four-year period, include options with and without performance-based features. The stock options expire in ten years from the date of grant. All options granted prior to 1997 became immediately exercisable upon approval by PE's shareholders of the business combination with Enova. The options were originally scheduled to vest annually over a service period ranging from three to five years. Sempra Energy's plans allow for the granting of dividend equivalents based upon performance goals. This feature provides grantees, upon exercise of the option, with the opportunity to receive all or a portion of the cash dividends that would have been paid on the shares if the shares had been outstanding since the grant date. Dividend equivalents are payable only if corporate goals are met and, for grants prior to July 1, 1998, if the exercise price exceeds the market value of the shares purchased. The percentage of dividends paid as dividend equivalents will depend upon the extent to which the performance goals are met. The following information is presented after conversion of PE stock into company stock as described in Note 1. Stock option activity is summarized in the following tables. - ----------------------------------------------------------------- Options With Performance Features - ----------------------------------------------------------------- Shares Average Options Under Exercise Exercisable Option Price at Year End - ----------------------------------------------------------------- December 31, 1995 846,188 $16.23 _ Granted 1,030,404 17.95 -------------------------------------------- December 31, 1996 1,876,592 17.17 282,063 Granted 1,040,103 20.37 Exercised (359,288) 16.53 Cancelled (71,190) 20.37 -------------------------------------------- December 31, 1997 2,486,217 18.51 1,513,545 Granted 2,131,803 25.23 Exercised (512,059) 17.12 Cancelled (509,301) 23.00 -------------------------------------------- December 31, 1998 3,596,660 $22.06 1,387,523 - ----------------------------------------------------------------- - ----------------------------------------------------------------- Options Without Performance Features - ----------------------------------------------------------------- Shares Average Options Under Exercise Exercisable Option Price at Year End - ----------------------------------------------------------------- December 31, 1995 2,302,018 $18.14 1,200,183 Exercised (304,520) 15.00 Cancelled (125,417) 26.05 -------------------------------------------- December 31, 1996 1,872,081 18.12 1,197,687 Exercised (493,848) 14.94 Cancelled (14,737) 35.24 -------------------------------------------- December 31, 1997 1,363,496 19.08 1,363,496 Granted 1,293,997 26.33 Exercised (596,629) 15.72 Cancelled (240,632) 29.78 -------------------------------------------- December 31, 1998 1,820,232 $23.92 523,661 - ----------------------------------------------------------------- Additional information on options outstanding at December 31, 1998, is as follows: - ----------------------------------------------------------------- Outstanding Options - ----------------------------------------------------------------- Range of Number Average Average Exercise of Remaining Exercise Prices Shares Life Price - ----------------------------------------------------------------- $12.80-$16.12 623,362 5.55 $15.29 $16.79-$20.36 1,584,272 7.47 $19.03 $24.10-$31.00 3,209,258 9.05 $25.82 ---------- 5,416,892 8.19 $22.64 - ----------------------------------------------------------------- Exercisable Options - ----------------------------------------------------------------- Range of Number Average Exercise of Exercise Prices Shares Price - ----------------------------------------------------------------- $12.80-$16.12 623,362 $15.29 $16.79-$20.36 1,109,878 $18.46 $24.11-$31.00 177,944 $26.70 ---------- 1,911,184 $18.20 - ----------------------------------------------------------------- The fair value of each option grant (including the dividend equivalent) was estimated on the date of grant using the modified Black-Scholes option-pricing model. Weighted average fair values for options granted in 1998, 1997, and 1996 were $8.20, $5.23 and $5.00, respectively. The assumptions that were used to determine these fair values are as follows: - ----------------------------------------------------------------- Year Ended December 31 1998 1997 1996 - ----------------------------------------------------------------- Stock price volatility 16% 18% 19% Risk-free rate of return 5.6% 6.4% 6.1% Annual dividend yield 0% 0% 0% Expected life 6 Years 3.8 Years 4.3 Years - ----------------------------------------------------------------- Compensation expense for the stock option grants was $11.7 million, $16.9 million and $5.5 million in 1998, 1997 and 1996, respectively. The differences between compensation cost included in net income and the related cost measured by the fair-value-based method defined in SFAS No. 123 are immaterial. 10 FINANCIAL INSTRUMENTS Fair Value The fair values of the company's financial instruments (cash, temporary investments, funds held in trust, notes receivable, investments in limited partnerships, dividends payable, short- and long-term debt, customer deposits, and preferred stock of subsidiaries) are not materially different from the carrying amounts, except for long-term debt and preferred stock of subsidiaries. The carrying amounts and fair values of long-term debt are $3.1 billion and $3.2 billion, respectively, at December 31, 1998, and $3.4 billion and $3.5 billion at December 31, 1997. The carrying amounts and fair values of subsidiaries' preferred stock are $204 million and $182 million, respectively, at December 31, 1998, and $279 million and $258 million, respectively, at December 31, 1997. The fair values of the first-mortgage and other bonds and preferred stock are estimated based on quoted market prices for them or for similar issues. The fair values of long-term notes payable are based on the present value of the future cash flows, discounted at rates available for similar notes with comparable maturities. Included in long-term debt are SDG&E's rate- reduction bonds. The carrying amounts and fair values of the bonds are $592 million and $607 million, respectively, at December 31, 1998. 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. Additional information on this topic is discussed in Note 2. 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, SDG&E had one interest-rate- swap agreement: a floating-to-fixed-rate swap associated with $45 million of variable-rate bonds maturing in 2002. SDG&E expects to hold this 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 5. Energy Derivatives Information on derivative financial instruments of SET is provided below. The company's regulated operations use energy derivatives for both price-risk management and trading 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. SoCalGas is subject to price risk on its natural gas purchases if its cost exceeds a 2-percent tolerance band above the benchmark price. This is discussed further in Note 14. SoCalGas becomes subject to price risk when positions are incurred during the buying, selling and storage of natural gas. As a result of the Gas Cost Incentive Mechanism (GCIM), SoCalGas enters into a certain amount of gas futures contracts in the open market with the intent of reducing gas costs within the GCIM tolerance band. The CPUC has approved the use of gas futures for managing risk associated with the GCIM. For the years ended December 31, 1998, 1997, and 1996, gains and losses from natural gas futures contracts are not material to SoCalGas' financial statements. Sempra Energy Trading SET derives a substantial portion of its revenue from market making and trading activities, as a principal, in natural gas, petroleum and electricity. It quotes bid and offer prices to end users and other market makers. It also earns trading profits as a dealer by structuring and executing transactions that permit its counterparties to manage their risk profiles. In addition, it takes positions in energy markets based on the expectation of future market conditions. These positions may be offset with similar positions or may be offset in the exchange-traded markets. These positions include options, forwards, futures and swaps. These financial instruments represent contracts with counterparties whereby payments are linked to or derived from energy-market indices or on terms predetermined by the contract, which may or may not be physically or financially settled by SET. For the year ended December 31, 1998, substantially all of SET's derivative transactions were held for trading and marketing purposes. Market risk arises from the potential for changes in the value of financial instruments resulting from fluctuations in natural gas, petroleum and electricity commodity-exchange prices and basis. Market risk is also affected by changes in volatility and liquidity in markets in which these instruments are traded. SET adjusts the book value of these derivatives to market each month with gains and losses recognized in earnings. These instruments are included in other current assets on the Consolidated Balance Sheet. Certain instruments such as swaps are entered into and closed out within the same month and, therefore, do not have any balance-sheet impact. Gains and losses are included in electric or natural gas revenue or expense, whichever is appropriate, in the Consolidated Income Statements. SET also carries an inventory of financial instruments. As trading strategies depend on both market making and proprietary positions, given the relationships between instruments and markets, those activities are managed in concert in order to maximize trading profits. SET's credit risk from financial instruments as of December 31, 1998, is represented by the positive fair value of financial instruments after consideration of master netting agreements and collateral. Credit risk disclosures, however, relate to the net accounting losses that would be recognized if all counterparties completely failed to perform their obligations. Options written do not expose SET to credit risk. Exchange-traded futures and options are not deemed to have significant credit exposure as the exchanges guarantee that every contract will be properly settled on a daily basis. The following table approximates the counterparty credit quality and exposure of SET expressed in terms of net replacement value (in millions of dollars): - ----------------------------------------------------------------- Futures, forward and swap Purchased Counterparty credit quality: contracts options Total - ----------------------------------------------------------------- AAA $32 $1 $33 AA 41 14 55 A 129 19 148 BBB 290 26 316 Below investment grade 69 2 71 Exchanges 30 8 38 - ----------------------------------------------------------------- $591 $70 $661 - ----------------------------------------------------------------- Financial instruments with maturities or repricing characteristics of 180 days or less, including cash and cash equivalents, are considered to be short-term and, therefore, the carrying values of these financial instruments approximate their fair values. SET's commodities owned, trading assets and trading liabilities are carried at fair value. The average fair values during the year, based on quarterly observation, for trading assets and trading liabilities which are considered financial instruments with off-balance-sheet risk approximate $952 million and $890 million, respectively. The fair values are net of the amounts offset pursuant to rights of setoff based on qualifying master netting arrangements with counterparties, and do not include the effects of collateral held or pledged. As of December 31, 1998, and 1997, SET's trading assets and trading liabilities approximate the following: - ----------------------------------------------------------------- December 31, (Dollars in millions) 1998 1997 - ----------------------------------------------------------------- Trading Assets Unrealized gains on swaps and forwards $756 $497 Due from commodity clearing organization and clearing brokers 75 41 OTC commodity options purchased 45 33 Due from trading counterparties 30 16 --------------------- Total $906 $587 - ----------------------------------------------------------------- Trading Liabilities Unrealized losses on swaps and forwards $740 $487 Due to trading counterparties 35 41 OTC commodity options written 30 29 --------------------- Total $805 $557 - ----------------------------------------------------------------- Notional amounts do not necessarily represent the amounts exchanged by parties to the financial instruments and do not measure SET's exposure to credit or market risks. The notional or contractual amounts are used to summarize the volume of financial instruments, but do not reflect the extent to which positions may offset one another. Accordingly, SET is exposed to much smaller amounts potentially subject to risk. The notional amounts of SET's financial instruments are: - ----------------------------------------------------------------- (Dollars in millions) Total - ----------------------------------------------------------------- Forwards and commodity swaps $5,916 Futures and exchange options 2,915 Options purchased 1,320 Options written 1,298 -------------- Total $11,449 - ----------------------------------------------------------------- 11 PREFERRED STOCK OF SUBSIDIARIES - ----------------------------------------------------------------- Pacific Enterprises Call December 31, (Dollars in millions except call price) Price 1998 1997 - ----------------------------------------------------------------- Cumulative preferred without par value: $4.75 Dividend, 200,000 shares authorized and outstanding $100.00 $20 $20 $4.50 Dividend, 300,000 shares authorized and outstanding $100.00 30 30 $4.40 Dividend, 100,000 shares authorized and outstanding $101.50 10 10 $4.36 Dividend, 200,000 shares authorized and outstanding $101.00 20 20 $4.75 Dividend, 253 shares authorized and outstanding $101.00 _ _ -------------- Total $80 $80 - ----------------------------------------------------------------- All or any part of every series of presently outstanding PE preferred stock is subject to redemption at PE's option at any time upon not less than 30 days' notice, at the applicable redemption price for each series, together with the accrued and accumulated dividends to the date of redemption. All series have one vote per share and cumulative preferences as to dividends. No shares of Unclassified or Class A preferred stock are outstanding. - ----------------------------------------------------------------- SoCalGas December 31, (Dollars in millions) 1998 1997 - ----------------------------------------------------------------- Not subject to mandatory redemption: $25 par value, authorized 1,000,000 shares 6% Series, 28,664 shares outstanding $1 $1 6% Series A, 783,032 shares outstanding 19 19 Without par value, authorized 10,000,000 shares 7.75% Series _ 75 -------------- $20 $95 - ----------------------------------------------------------------- None of SoCalGas' series of preferred stock is callable. All series have one vote per share and cumulative preferences as to dividends. On February 2, 1998, SoCalGas redeemed all outstanding shares of 7.75% Series Preferred Stock at a price per share of $25 plus $0.09 of dividends accruing to the date of redemption. The total cost to SoCalGas was approximately $75.3 million. - ----------------------------------------------------------------- SDG&E Call December 31, (Dollars in millions except call price) Price 1998 1997 - ----------------------------------------------------------------- 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 7 7 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 $79 $79 -------------- 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. 12 SHAREHOLDERS EQUITY AND EARNINGS PER SHARE The company's outstanding stock options represent the only forms of potential common stock at December 31, 1998, 1997 and 1996. The reconciliation between basic and diluted EPS is as follows: - ----------------------------------------------------------------- Income Shares Earnings (in millions) (in thousands) Per Share - ----------------------------------------------------------------- 1998: Basic $294 236,423 $1.24 Effect of dilutive stock options 701 - ----------------------------------------------------------------- Diluted $294 237,124 $1.24 - ----------------------------------------------------------------- 1997: Basic $432 236,662 $1.83 Effect of dilutive stock options 587 - ----------------------------------------------------------------- Diluted $432 237,249 $1.82 - ----------------------------------------------------------------- 1996: Basic $427 240,825 $1.77 Effect of dilutive stock options 332 - ----------------------------------------------------------------- Diluted $427 241,157 $1.77 - ----------------------------------------------------------------- The company is authorized to issue 750,000,000 shares of no par value common stock and 50,000,000 shares of Preferred Stock. At December 31, 1998, there were 240,026,439 shares of common stock outstanding, compared to 235,598,111 shares outstanding at December 31, 1997. No shares of Preferred Stock were issued and outstanding. 13 COMMITMENTS AND CONTINGENCIES Natural Gas Contracts The company buys natural gas under several short-term and long-term contracts. Short-term purchases are based on monthly spot-market prices. SoCalGas has commitments for firm pipeline capacity under contracts with pipeline companies that expire at various dates through the year 2006. These agreements provide for payments of an annual reservation charge. SoCalGas recovers such fixed charges in rates. SDG&E 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. A U.S. Court of Appeal has upheld a U.S. District Court's invalidation of the contracts with two of these suppliers. 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 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 $193 $288 2000 195 170 2001 197 175 2002 197 179 2003 193 181 Thereafter 587 _ ---------------------------------- Total minimum payments $1,562 $993 - ----------------------------------------------------------------- Total payments under the short-term and long-term contracts were $1.0 billion in 1998, $1.2 billion in 1997, and $1.0 billion in 1996. All of SDG&E's 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 14, 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 14. Leases The company has leases (primarily operating) on real and personal property expiring at various dates from 1999 to 2030. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 2 percent to 7 percent. The rentals payable under these leases are determined on both fixed and percentage bases, and most leases contain options to extend, which are exercisable by the company. The company also 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. The minimum rental commitments payable in future years under all noncancellable leases are: - ----------------------------------------------------------------- Operating Capitalized (Dollars in millions) Leases Leases - ----------------------------------------------------------------- 1999 $60 $31 2000 58 14 2001 55 14 2002 52 14 2003 51 11 Thereafter 380 9 ------------------------------ Total future rental commitment $656 93 Imputed interest (6% to 9%) (17) ----------- Net commitment $76 - ----------------------------------------------------------------- Rent expense totaled $105 million in 1998, $137 million in 1997 and $146 million in 1996. In connection with the quasi-reorganization described in Note 2, PE established reserves of $102 million to fair value operating leases related to its headquarters and other leases at December 31, 1992. The remaining amount of these reserves was $76 million at December 31, 1998. These leases are reflected in the above table. Environmental Issues The company 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. SoCalGas and SDG&E incur significant costs to operate their 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. The company's capital expenditures to comply with environmental laws and regulations were $1 million in 1998, $5 million in 1997, and $9 million in 1996, and are not expected to be significant during the next five years. These expenditures primarily include the 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. The company has been associated with various sites which may require remediation under federal, state or local environmental laws. The company is unable to determine fully 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. The company does not anticipate that such costs, net of the portion recoverable in rates, will be significant. As discussed in Note 14, restructuring of the California electric-utility industry will change the way utility rates are set and costs are recovered. SDG&E 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 The company 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 the company'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, $17 million in 1997, and $15 million in 1996. Concentration of Credit Risk The company 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 and SoCalGas grant credit to their utility customers, substantially all of whom are located in their service territories, which together cover most of Southern California and a portion of central California. SET monitors and controls its credit-risk exposures through various systems which evaluate its credit risk, and through credit approvals and limits. To manage the level of credit risk, SET deals with a majority of counterparties with good credit standing, enters into master netting arrangements whenever possible and, where appropriate, obtains collateral. Master netting agreements incorporate rights of setoff that provide for the net settlement of subject contracts with the same counterparty in the event of default. 14 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, 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. Additional information is provided in Note 10. 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 provides 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 being 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. Gas Industry Restructuring The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating 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 and SoCalGas 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 both SoCalGas and 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. SoCalGas' PBR is in effect through December 31, 2002; however, the CPUC decision allows for the possibility that changes to the PBR mechanism could be adopted in a decision to be issued in SoCalGas' 1999 Biennial Cost Allocation Proceeding, which is anticipated to become effective before year end 1999. Key elements of the SoCalGas PBR include an initial reduction in base rates, an indexing mechanism that limits future rate increases to the inflation rate less a productivity factor, a sharing mechanism with customers if earnings exceed the authorized rate of return on rate base, and rate refunds to customers if service quality deteriorates. Specifically, the key elements of SoCalGas' PBR include the following: - --Earnings up to 25 basis points in excess of the authorized rate of return on rate base are retained 100 percent by shareholders. Earnings that exceed the authorized rate of return on rate base by greater than 25 basis points are shared between customers and shareholders on a sliding scale that begins with 75 percent of the additional earnings being given back to customers and declining to 0 percent as earned returns approach 300 basis points above authorized amounts. There is no sharing if actual earnings fall below the authorized rate of return. In 1999, SoCalGas is authorized to earn a 9.49 percent return on rate base, the same as in 1998. - --Revenue or base margin per customer is indexed based on inflation less an estimated productivity factor of 2.1 percent in the first year (1998), increasing 0.1 percent per year up to 2.5 percent in the fifth year (2002). This factor includes 1 percent to approximate the projected impact of a declining rate base. - --The CPUC decision allows for pricing flexibility for residential and small commercial customers, with any shortfalls in revenue being borne by shareholders and with any increase in revenue shared between shareholders and customers. Under SoCalGas' PBR, annual cost of capital proceedings are replaced by an automatic adjustment mechanism if changes in certain indices exceed established tolerances. The mechanism is triggered if the 12-month trailing average of actual market interest rates increases or decreases by more than 150 basis points and is forecasted to continue to vary by at least 150 basis points for the next year. If this occurs, there would be an automatic adjustment of rates for the change in the cost of capital according to a preestablished formula which applies a percentage of the change to various capital components. SDG&E continues to participate 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 (similar to the indexing mechanism in SoCalGas' PBR) rather than the rate-indexing mechanism proposed by SDG&E. In addition, the proposed decision recommends much tighter earnings sharing bands (similar to SoCalGas'). 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. Comprehensive Settlement Of Natural Gas Regulatory Issues In July 1994, the CPUC approved a comprehensive settlement for SoCalGas (Comprehensive Settlement) of a number of regulatory issues, including rate recovery of a significant portion of the restructuring costs associated with certain long-term contracts with suppliers of California-offshore and Canadian natural gas. In the past, the cost of these supplies had been substantially in excess of SoCalGas' average delivered cost for all natural gas supplies. The restructured contracts substantially reduced the ongoing delivered costs of these supplies. The Comprehensive Settlement permits SoCalGas to recover in utility rates approximately 80 percent of the contract-restructuring costs of $391 million and accelerated amortization of related pipeline assets of approximately $140 million, together with interest, incurred prior to January 1, 1999. In addition to the supply issues, the Comprehensive Settlement addressed the following other regulatory issues: - --Noncore Customer Rates. The Comprehensive Settlement changed the procedures for determining noncore rates to be charged by SoCalGas for the five-year period commencing August 1, 1994. These rates are based upon SoCalGas' recorded throughput to these customers for 1991. SoCalGas will bear the full risk of any declines in noncore deliveries from 1991 levels. Any revenue enhancement from deliveries in excess of 1991 levels will be limited by a crediting account mechanism that will require a credit to customers of 87.5 percent of revenues in excess of certain limits. These annual limits above which the credit is applicable increase from $11 million to $19 million over the five-year period from August 1, 1994, through July 31, 1999. SoCalGas' ability to report as earnings the results from revenues in excess of SoCalGas' authorized return from noncore customers due to volume increases has been limited for the five years beginning August 1, 1994, as a result of the Comprehensive Settlement. The 1999 Biennial Cost Allocation Proceeding is intended to adopt measures to replace this aspect of the Comprehensive Settlement when it expires during 1999. - --Gas Cost Incentive Mechanism (GCIM). On April 1, 1994, SoCalGas implemented a new process for evaluating its natural gas purchases, substantially replacing the previous process of reasonableness reviews. Initially a three-year pilot program, in December 1998 the CPUC extended the GCIM program indefinitely. Automatic annual extensions to the program will continue unless the CPUC issues an order stating otherwise. GCIM compares SoCalGas' cost of natural gas with a benchmark level, which is the average price of 30-day firm spot supplies in the basins in which SoCalGas purchases the natural gas. The mechanism permits full recovery of all costs within a "tolerance band" above the benchmark price and refunds all savings within a "tolerance band" below the benchmark price. The costs or savings outside the "tolerance band" are shared equally between customers and shareholders. The CPUC approved the use of natural gas futures for managing risk associated with the GCIM. SoCalGas enters into natural gas futures contracts in the open market on a limited basis to mitigate risk and better manage natural gas costs. In June 1997, SoCalGas requested a shareholder award of $11 million, which was approved by the CPUC in June 1998 and is included in pretax income in 1998. In June 1998, SoCalGas filed its annual GCIM application with the CPUC requesting an award of $2 million for the annual period ended March 31, 1998. This request was approved by the CPUC in December 1998 and is included in pretax income in 1998. - --Attrition Allowances. The Comprehensive Settlement authorized SoCalGas an annual allowance for increases in operating and maintenance expenses. However, no attrition allowance was authorized for 1997 and beyond, based on an agreement reached as part of the PBR application. PE and SoCalGas recorded the impact of the Comprehensive Settlement in 1993. Upon giving effect to liabilities previously recognized by the companies, the costs of the Comprehensive Settlement, including the restructuring of natural gas supply contracts, did not result in any future charge to PE's earnings. Biennial Cost Allocation Proceeding (BCAP) In the second quarter of 1997, the CPUC issued a decision on SoCalGas' 1996 BCAP filing. In this decision, the CPUC considered SoCalGas' relinquishments of interstate pipeline capacity on both the El Paso and Transwestern pipelines. This resulted in a reduction in the pipeline demand charges allocated to SoCalGas' customers and surcharges allocated to firm capacity holders through pipeline rate-case settlements adopted at the FERC. However, the CPUC and FERC are reviewing the decision. In October 1998, SoCalGas and SDG&E filed 1999 BCAP applications requesting that new rates become effective August 1, 1999 and remain in effect through December 31, 2002. The proposed beginning date follows the conclusion of the Comprehensive Settlement (discussed above), and the proposed end date aligns with the expiration of SoCalGas' and SDG&E's PBRs. The applications seek overall decreases in natural gas revenues of $204 million for SoCalGas and $9 million for SDG&E. 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. For 1999, SoCalGas is authorized to earn a rate of return on common equity (ROE) of 11.6 percent and a 9.49 percent return on rate base (ROR), the same as in 1998, unless interest-rate changes are large enough to trigger an automatic adjustment as discussed above under "Performance-Based Regulation." For SDG&E, electric-industry restructuring is changing the method of calculating the utility's annual cost of capital. In May 1998, SDG&E 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 ROE, which would produce an overall 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 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 business combination of Enova and PE (see Note 1). 15 SEGMENT INFORMATION The company, primarily an energy-services company, has three separately managed reportable segments comprised of SoCalGas, SDG&E and Sempra Energy Trading (SET). The two utilities operate in essentially separate service territories under separate regulatory frameworks and rate structures set by the CPUC. As described in Note 1, SDG&E provides electric and natural gas service to San Diego and southern Orange counties. SoCalGas is a natural gas distribution utility, serving customers throughout most of Southern California and part of central California. SET is based in Stamford, Connecticut, and is engaged in the nationwide wholesale trading and marketing of natural gas, power and petroleum. 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 net income. Intersegment transactions generally are recorded the same as sales or transactions with third parties. Utility transactions are primarily based on rates set by the CPUC and FERC. - ----------------------------------------------------------------- For the year ended December 31 (Dollars in millions) 1998 1997 1996 - ----------------------------------------------------------------- Operating Revenues: Southern California Gas $2,427 $2,641 $2,422 San Diego Gas & Electric 2,749 2,167 1,939 Sempra Energy Trading 110 _ _ Intersegment revenues (59) (55) (60) All other 254 316 195 ------------------------------ Total $5,481 $5,069 $4,496 ------------------------------ Interest Revenue: Southern California Gas $4 $16 $5 San Diego Gas & Electric 40 9 7 Sempra Energy Trading 3 _ _ All other interest 3 21 23 ------------------------------ Total interest 50 46 35 Sundry income (loss) (6) 12 (7) ------------------------------ Total other income $44 $58 $28 ------------------------------ Depreciation and Amortization: Southern California Gas $254 $251 $248 San Diego Gas & Electric (See Note 14) 603 324 314 Sempra Energy Trading 13 _ _ All other 59 29 25 ------------------------------ Total $929 $604 $587 ------------------------------ Interest Expense: Southern California Gas $80 $87 $86 San Diego Gas & Electric 116 86 91 Sempra Energy Trading 5 _ _ All other 6 33 23 ------------------------------ Total $207 $206 $200 ------------------------------ Income Tax Expense (Benefit): Southern California Gas $128 $178 $148 San Diego Gas & Electric 142 219 198 Sempra Energy Trading (9) _ _ All other (123) (96) (46) ------------------------------ Total $138 $301 $300 ------------------------------ Net Income: Southern California Gas $158 $231 $193 San Diego Gas & Electric 185 232 216 Sempra Energy Trading (13) _ _ All other (36) (31) 18 ------------------------------ Total $294 $432 $427 ------------------------------ - ----------------------------------------------------------------- At December 31, or for the year then ended (Dollars in millions) 1998 1997 1996 - ----------------------------------------------------------------- Assets: Southern California Gas $3,834 $4,205 $4,354 San Diego Gas & Electric 4,257 4,654 4,161 Sempra Energy Trading 1,225 846 _ All other 1,253 1,181 1,257 Eliminations (113) (130) (10) ------------------------------ Total $10,456 $10,756 $9,762 ------------------------------ Capital Expenditures: Southern California Gas $128 $159 $197 San Diego Gas & Electric 227 197 209 Sempra Energy Trading _ _ _ All other 83 41 7 ------------------------------ Total $438 $397 $413 ------------------------------ Geographic Information: Long-lived assets: United States $5,849 $5,904 $6,647 Latin America 140 67 50 ------------------------------ Total $5,989 $5,971 $6,697 ------------------------------ Operating Revenues: United States $5,474 $5,058 $4,488 Latin America 7 11 8 ------------------------------ Total $5,481 $5,069 $4,496 - ----------------------------------------------------------------- 16 SUBSEQUENT EVENT On February 22, 1999, the company and KN Energy, Inc. (KN Energy) announced that their respective boards of directors approved the company'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 company 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. Sempra Energy Quarterly Financial Data (unaudited) Quarter ended ------------------------------------------------------- March 31 June 30 September 30 December 31 Dollars in millions except per share amounts - ------------------------------------------------------------------------------------------------------------ 1998 Revenues and other income $ 1,350 $ 1,335 $ 1,398 $ 1,442 Operating expenses 1,164 1,249 1,192 1,281 ----------------------------------------------------- Operating income $ 186 $ 86 $ 206 $ 161 ----------------------------------------------------- Net income $ 87 $ 31 $ 91 $ 85 Average common shares outstanding (diluted) 236.4 236.9 237.4 237.6 Net income per common share (diluted) $ 0.37 $ 0.13 $ 0.38 $ 0.36 1997 Revenues and other income $ 1,301 $ 1,130 $ 1,251 $ 1,445 Operating expenses 1,093 878 1,018 1,199 ----------------------------------------------------- Operating income $ 208 $ 252 $ 233 $ 246 ----------------------------------------------------- Net income $ 98 $ 112 $ 102 $ 120 Average common shares outstanding (diluted) 239.2 236.3 236.2 236.6 Net income per common share (diluted) $ 0.41 $ 0.47 $ 0.43 $ 0.51 - ------------------------------------------------------------------------------------------------------------ Quarterly Common Stock Data (unaudited) 1998 1997 -------------------------------------------------------------------------- First Second Third Fourth First Second Third Fourth Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter - ----------------------------------------------------------------------------------------------------------- Market price High * * 28 29 5/16 * * * * Low * * 23 3/4 24 9/16 * * * * Dividends declared(1) $0.32 $0.46 $0.39 $0.39 $0.31 $0.45 $0.19 $0.32 - ----------------------------------------------------------------------------------------------------------- *Not presented as the formation of Sempra Energy was not completed until June 26, 1998. (1) Prior to the formation of Sempra Energy on June 26, 1998, dividends declared represents the sum of dividends declared by Pacific Enterprises and Enova Corporation, divided by the sum of the combining companies' shares after the conversion of PE's shares into Sempra Energy shares as described in Note 1 to the notes to Consolidated Financial Statements.

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.

UT 1,000,000 YEAR DEC-31-1998 DEC-31-1998 PER-BOOK 5,252 737 2,458 980 1,029 10,456 1,883 0 1,030 2,913 25 179 2,795 43 0 0 330 0 0 0 4,171 10,456 5,481 138 4,886

5,024 457 44 501 207 294 0

294 376 0 1,323 1.24 1.24 PREFERRED DIVIDEND OF SUBSIDIARY INCLUDED IN OTHER OPERATING EXPENSE

Exhibit 10.1 AMENDMENT TO EMPLOYMENT AGREEMENT By this Agreement, Sempra Energy (the "Company"), a California corporation formerly known as Mineral Energy Company, and STEPHEN BAUM (the "Executive") amend the Employment Agreement (the "Agreement") between Mineral Energy Company and Executive dated October 12, 1996, to be effective December 1, 1998, as follows: 1. Paragraph 4 (d) (iii) of the Agreement is stricken and replaced with the following language: "(iii) the relocation of the Executive's principal place of employment to a location away from the Company's headquarters or a relocation of the Company's headquarters to a location further away which is both further away from Executive's residence and more than thirty (30) miles from such headquarters or a substantial increase in the Executive's business travel obligations outside of the Southern California area as of the Effective Date other than any such increase that (A) arises in connection with extraordinary business activities of the Company and (B) is understood not to be part of the Executive's regular duties with the Company;" 2. Paragraph 5 (a) (vi) of the Agreement is modified in its opening phrase to read: "(vi) Continuation of Welfare Benefits. For a period of three (3) years or until the Executive is eligible for retiree medical benefits, whichever is longer, ..." 3. Paragraphs 5 (d), (e) and (f) of the Agreement are stricken and replaced by the following: "(d) Code Section 280G (i) Gross-Up. Notwithstanding any other provisions of this Agreement, in the event that any payment or benefit received or to be received by the Executive (whether pursuant to the terms of this Agreement or any other plan, arrangement or agreement with (A) the Company, (B) any Person (as defined in Section 4(e))whose actions result in a Change in Control or (C) any Person affiliated with the Company or such Person) (all such payments and benefits, including the Severance Payments, being hereinafter called the "Total Payments") would be subject (in whole or part) to the tax (the "Excise Tax") imposed under section 4999 of the Code, the Company shall pay to the Executive such additional amounts (the "Gross-Up Payment") such that the net amount retained by the Executive, after deduction of any Excise Tax on the Total Payments and any federal, state and local income and employment taxes and Excise Tax upon the Gross-Up Payment, shall be equal to the Total Payments. For purposes of determining the amount of the Gross-Up Payment, the Executive shall be deemed to pay federal income tax at the highest marginal rate of federal income taxation in the calendar year in which the Gross-Up Payment is to be made and state and local income taxes at the highest marginal rate of taxation in the state and locality of the Executive's residence on the date on which the Gross-Up Payment is calculated for purposes of this section, net of the maximum reduction in federal income taxes which could be obtained from deduction of such state and local taxes. In the event that the Excise Tax is subsequently determined to be less than the amount taken into account hereunder, the Executive shall repay to the Company, at the time that the amount of such reduction in Excise Tax is finally determined, the portion of the Gross-Up Payment attributable to such reduction (plus that portion of the Gross-Up Payment attributable to the Excise Tax and federal, state and local income tax imposed on the Gross-Up Payment being repaid by the Executive to the extent that such repayment results in a reduction in Excise Tax and/or a federal, state or local income tax deduction) plus interest on the amount of such repayment at the rate provided in section 1274(b)(2)(B) of the Code. In the event that the Excise Tax is determined to exceed the amount taken into account hereunder (including by reason of any payment the existence or amount of which cannot be determined at the time of the Gross-Up Payment), the Company shall make an additional Gross-Up Payment in respect of such excess (plus any interest, penalties or additions payable by the Executive with respect to such excess) at the time that the amount of such excess is finally determined. The Executive and the Company shall each reasonably cooperate with the other in connection with any administrative or judicial proceedings concerning the existence or amount of liability for Excise Tax with respect to the Total Payments. (ii) Accounting Firm. All determinations to be made with respect to this Section 5 (d) shall be made by the Company's independent accounting firm (or, in the case of a payment following a Change in Control, the accounting firm that was, immediately prior to the Change in Control, the Company's independent auditor). The accounting firm shall be paid by the Company for its services performed hereunder." 4. Sections 5 (e) and (f) of the Agreement are added to read: "(e) Outplacement Services. The Executive shall receive outplacement services suitable to his or her position for a period of eighteen (18) months following the Date of Termination, or if earlier, until the first acceptance of an offer of employment with a subsequent employer, in an aggregate amount not to exceed $50,000. (f) Financial Planning Services. The Executive shall receive financial planning services for a period of eighteen (18) months following the Date of Termination at a level consistent with the benefits provided under the Company's financial planning program for the Executive, as in effect immediately prior to the Date of Termination." 5. Section 5(h) of the Agreement is added to read: (h) Notwithstanding anything contained herein, if a Change in Control occurs and if, prior to the date of the Change in Control, the Executive's employment is terminated by the Company (other than for Cause, death or Disability), or by the Executive for Good Reason, and if such Termination (i) was at the request of a third party who has taken steps reasonably calculated to effect the Change in Control or (ii) otherwise arose in connection with or in anticipation of the Change in Control, then such Termination shall be treated as a Termination following a Change in Control for purposes of this Agreement (including, without limitation, for purposes of determining the amounts of the Severance Payments under this Section 5). 6. Paragraph 8 ("Arbitration") of the Agreement is stricken and replaced with the following language: "8. Dispute Resolution. Any disagreement, dispute, controversy or claim arising out of or relating to this Agreement or the interpretation of this Agreement or any arrangements relating to this Agreement or contemplated in this Agreement or the breach, termination or invalidity thereof shall be settled by final and binding arbitration administered by JAMS/Endispute in San Diego, California in accordance with the then existing JAMS/Endispute Arbitration Rules and Procedures for Employment Disputes. In the event of such an arbitration proceeding, the Executive and the Company shall select a mutually acceptable neutral arbitrator from among the JAMS/Endispute panel of arbitrators. In the event the Executive and the Company cannot agree on an arbitrator, the Administrator of JAMS/Endispute will appoint an arbitrator. Neither the Executive nor the Company nor the arbitrator shall disclose the existence, content, or results of any arbitration hereunder without the prior written consent of all parties. Except as provided herein, the Federal Arbitration Act shall govern the interpretation, enforcement and all proceedings. The arbitrator shall apply the substantive law (and the law of remedies, if applicable) of the state of California, or federal law, or both, as applicable and the arbitrator is without jurisdiction to apply any different substantive law. The arbitrator shall have the authority to entertain a motion to dismiss and/or a motion for summary judgment by any party and shall apply the standards governing such motions under the Federal Rules of Civil Procedure. The arbitrator shall render an award and a written, reasoned opinion in support thereof. Judgment upon the award may be entered in any court having jurisdiction thereof." IN WITNESS WHEREOF, the Executive and, pursuant to authorization from its Board of Directors, the Company have caused this Amendment to Employment Agreement to be executed as of the effective date, above. SEMPRA ENERGY By: ________________________ Richard D. Farman Chairman & Chief Executive Officer ________________________ STEPHEN BAUM 1 3 4TOPS/123198 4TOPS/123198

Exhibit 10.02 AMENDMENT TO EMPLOYMENT AGREEMENT By this Agreement, Sempra Energy (the "Company"), a California corporation formerly known as Mineral Energy Company, and RICHARD FARMAN (the "Executive") amend the Employment Agreement (the "Agreement") between Mineral Energy Company and Executive dated October 12, 1996, to be effective December 1, 1998, as follows: 1.Paragraph 4 (e) (iii) of the Agreement is stricken and replaced with the following language: "(iii) the relocation of the Executive's principal place of employment to a location away from the Company's headquarters or a relocation of the Company's headquarters to a location further away which is both further away from Executive's residence and more than thirty (30) miles from such headquarters or a substantial increase in the Executive's business travel obligations outside of the Southern California area as of the Effective Date other than any such increase that (A) arises in connection with extraordinary business activities of the Company and (B) is understood not to be part of the Executive's regular duties with the Company;" 2. Paragraph 5 (a) (vi) of the Agreement is modified in its opening phrase to read: "(vi) Continuation of Welfare Benefits. For a period of three (3) years or until the Executive is eligible for retiree medical benefits, whichever is longer, ..." 3. Paragraphs 5 (d), (e) and (f) of the Agreement are stricken and replaced by the following: "(d) Code Section 280G (i) Gross-Up. Notwithstanding any other provisions of this Agreement, in the event that any payment or benefit received or to be received by the Executive (whether pursuant to the terms of this Agreement or any other plan, arrangement or agreement with (A) the Company, (B) any Person (as defined in Section 4(e))whose actions result in a Change in Control or (C) any Person affiliated with the Company or such Person) (all such payments and benefits, including the Severance Payments, being hereinafter called the "Total Payments") would be subject (in whole or part) to the tax (the "Excise Tax") imposed under section 4999 of the Code, the Company shall pay to the Executive such additional amounts (the "Gross-Up Payment") such that the net amount retained by the Executive, after deduction of any Excise Tax on the Total Payments and any federal, state and local income and employment taxes and Excise Tax upon the Gross-Up Payment, shall be equal to the Total Payments. For purposes of determining the amount of the Gross-Up Payment, the Executive shall be deemed to pay federal income tax at the highest marginal rate of federal income taxation in the calendar year in which the Gross-Up Payment is to be made and state and local income taxes at the highest marginal rate of taxation in the state and locality of the Executive's residence on the date on which the Gross-Up Payment is calculated for purposes of this section, net of the maximum reduction in federal income taxes which could be obtained from deduction of such state and local taxes. In the event that the Excise Tax is subsequently determined to be less than the amount taken into account hereunder, the Executive shall repay to the Company, at the time that the amount of such reduction in Excise Tax is finally determined, the portion of the Gross-Up Payment attributable to such reduction (plus that portion of the Gross-Up Payment attributable to the Excise Tax and federal, state and local income tax imposed on the Gross-Up Payment being repaid by the Executive to the extent that such repayment results in a reduction in Excise Tax and/or a federal, state or local income tax deduction) plus interest on the amount of such repayment at the rate provided in section 1274(b)(2)(B) of the Code. In the event that the Excise Tax is determined to exceed the amount taken into account hereunder (including by reason of any payment the existence or amount of which cannot be determined at the time of the Gross-Up Payment), the Company shall make an additional Gross-Up Payment in respect of such excess (plus any interest, penalties or additions payable by the Executive with respect to such excess) at the time that the amount of such excess is finally determined. The Executive and the Company shall each reasonably cooperate with the other in connection with any administrative or judicial proceedings concerning the existence or amount of liability for Excise Tax with respect to the Total Payments. (ii) Accounting Firm. All determinations to be made with respect to this Section 5 (d) shall be made by the Company's independent accounting firm (or, in the case of a payment following a Change in Control, the accounting firm that was, immediately prior to the Change in Control, the Company's independent auditor). The accounting firm shall be paid by the Company for its services performed hereunder." 4. Sections 5 (e) and (f) of the Agreement are added to read: "(e) Outplacement Services. The Executive shall receive outplacement services suitable to his or her position for a period of eighteen (18) months following the Date of Termination, or if earlier, until the first acceptance of an offer of employment with a subsequent employer, in an aggregate amount not to exceed $50,000. (f) Financial Planning Services. The Executive shall receive financial planning services for a period of eighteen (18) months following the Date of Termination at a level consistent with the benefits provided under the Company's financial planning program for the Executive, as in effect immediately prior to the Date of Termination." 5. Section 5(h) of the Agreement is added to read: (h) Notwithstanding anything contained herein, if a Change in Control occurs and if, prior to the date of the Change in Control, the Executive's employment is terminated by the Company (other than for Cause, death or Disability), or by the Executive for Good Reason, and if such Termination (i) was at the request of a third party who has taken steps reasonably calculated to effect the Change in Control or (ii) otherwise arose in connection with or in anticipation of the Change in Control, then such Termination shall be treated as a Termination following a Change in Control for purposes of this Agreement (including, without limitation, for purposes of determining the amounts of the Severance Payments under this Section 5). 6. Paragraph 8 ("Arbitration") of the Agreement is stricken and replaced with the following language: "8. Dispute Resolution. Any disagreement, dispute, controversy or claim arising out of or relating to this Agreement or the interpretation of this Agreement or any arrangements relating to this Agreement or contemplated in this Agreement or the breach, termination or invalidity thereof shall be settled by final and binding arbitration administered by JAMS/Endispute in San Diego, California in accordance with the then existing JAMS/Endispute Arbitration Rules and Procedures for Employment Disputes. In the event of such an arbitration proceeding, the Executive and the Company shall select a mutually acceptable neutral arbitrator from among the JAMS/Endispute panel of arbitrators. In the event the Executive and the Company cannot agree on an arbitrator, the Administrator of JAMS/Endispute will appoint an arbitrator. Neither the Executive nor the Company nor the arbitrator shall disclose the existence, content, or results of any arbitration hereunder without the prior written consent of all parties. Except as provided herein, the Federal Arbitration Act shall govern the interpretation, enforcement and all proceedings. The arbitrator shall apply the substantive law (and the law of remedies, if applicable) of the state of California, or federal law, or both, as applicable and the arbitrator is without jurisdiction to apply any different substantive law. The arbitrator shall have the authority to entertain a motion to dismiss and/or a motion for summary judgment by any party and shall apply the standards governing such motions under the Federal Rules of Civil Procedure. The arbitrator shall render an award and a written, reasoned opinion in support thereof. Judgment upon the award may be entered in any court having jurisdiction thereof." IN WITNESS WHEREOF, the Executive and, pursuant to authorization from its Board of Directors, the Company have caused this Amendment to Employment Agreement to be executed as of the effective date, above. SEMPRA ENERGY By: ________________________ By: ________________________ Stephen L. Baum G. Joyce Rowland Vice Chairman, President & COO Senior Vice President, Human Resources ________________________ RICHARD FARMAN 1 3 4TOPS/123198 4TOPS/123198

Exhibit 10.03 AMENDMENT TO EMPLOYMENT AGREEMENT By this Agreement, Sempra Energy (the "Company"), a California corporation formerly known as Mineral Energy Company, and DONALD FELSINGER (the "Executive") amend the Employment Agreement (the "Agreement") between Mineral Energy Company and Executive dated October 12, 1996, to be effective December 1, 1998, as follows: 1. Paragraph 4 (d) (iii) of the Agreement is stricken and replaced with the following language: "(iii) the relocation of the Executive's principal place of employment to a location away from the Company's headquarters or a relocation of the Company's headquarters to a location further away which is both further away from Executive's residence and more than thirty (30) miles from such headquarters or a substantial increase in the Executive's business travel obligations outside of the Southern California area as of the Effective Date other than any such increase that (A) arises in connection with extraordinary business activities of the Company and (B) is understood not to be part of the Executive's regular duties with the Company;" 2. Paragraph 5 (a) (vi) of the Agreement is modified in its opening phrase to read: "(vi) Continuation of Welfare Benefits. For a period of three (3) years or until the Executive is eligible for retiree benefits, whichever is longer, ..." 3. Paragraphs 5 (d), (e) and (f) of the Agreement are stricken and replaced by the following: "(d) Code Section 280G (i) Gross-Up. Notwithstanding any other provisions of this Agreement, in the event that any payment or benefit received or to be received by the Executive (whether pursuant to the terms of this Agreement or any other plan, arrangement or agreement with (A) the Company, (B) any Person (as defined in Section 4(e))whose actions result in a Change Control or (C) any Person affiliated with the Company or such Person) (all such payments and benefits, including the Severance Payments, hereinafter called the "Total Payments") would be subject (in whole or part) to the tax (the "Excise Tax") imposed under section 4999 of the Code, the Company shall pay to the Executive such additional amounts (the "Gross-Up Payment") such that the net amount retained by the Executive, after deduction of any Excise Tax on the Total Payments and any federal, state and local income and employment taxes and Excise Tax upon the Gross-Up Payment, shall be equal to the Total Payments. For purposes of determining the amount of the Gross-Up Payment, the Executive shall be deemed to pay federal income tax at the highest marginal rate of federal income taxation in the calendar year in which the Gross-Up Payment is be made and state and local income taxes at the highest marginal rate taxation in the state and locality of the Executive's residence on the date on which the Gross-Up Payment is calculated for purposes of this section, net of the maximum reduction in federal income taxes which could be obtained from deduction of such state and local taxes. In the event that the Excise Tax is subsequently determined to be less than the amount taken into account hereunder, the Executive shall repay to the Company, at the time that the amount of such reduction in Excise Tax is finally determined, the portion of the Gross-Up Payment attributable to such reduction (plus that portion of the Gross-Up Payment attributable to the Excise Tax and federal, state and local income tax imposed on the Gross-Up Payment being repaid by the Executive to the extent that such repayment results in a reduction in Excise Tax and/or a federal, state or local income tax deduction) plus interest on the amount of such repayment at the rate provided in section 1274(b)(2)(B) of the Code. In the event that the Excise Tax is determined to exceed the amount taken into account hereunder (including by reason of any payment the existence or amount of cannot be determined at the time of the Gross-Up Payment), the Company shall make an additional Gross-Up Payment in respect of such excess (plus any interest, penalties or additions payable by the Executive with respect to such excess) at the time that the amount of such excess is finally determined. The Executive and the Company shall each reasonably cooperate with the other in connection with any administrative or judicial proceedings concerning the existence or amount of liability for Excise with respect to the Total Payments. (ii) Accounting Firm. All determinations to be made with respect to this Section 5 (d) shall be made by the Company's independent accounting firm (or, in the case of a payment following a Change in Control, the accounting firm that was, immediately prior to the Change in Control, the Company's independent auditor). The accounting firm shall be paid by the Company for its services performed hereunder." 4. Sections 5 (e) and (f) of the Agreement are added to read: "(e) Outplacement Services. The Executive shall receive outplacement services suitable to his or her position for a period of eighteen (18) months following the Date of Termination, or if earlier, until the first acceptance of an offer of employment with a subsequent employer, in an aggregate amount not to exceed $50,000. (f) Financial Planning Services. The Executive shall receive financial planning services for a period of eighteen (18) months following the Date of Termination at a level consistent with the benefits provided under the Company's financial planning program for the Executive, as in effect immediately prior to the Date of Termination." 5. Section 5(h) of the Agreement is added to read: (h) Notwithstanding anything contained herein, if a Change in Control occurs and if, prior to the date of the Change in Control, the Executive's employment is terminated by the Company (other than for Cause, death or Disability), or by the Executive for Good Reason, and if such Termination (i) was at the request of a third party who has taken steps reasonably calculated to effect the Change in Control or (ii) otherwise arose in connection with or in anticipation of the Change in Control, then such Termination shall be treated as a Termination following a Change in Control for purposes of this Agreement (including, without limitation, for purposes of determining the amounts of the Severance Payments under this Section 5). 6. Paragraph 8 ("Arbitration") of the Agreement is stricken and replaced with the following language: "8. Dispute Resolution. Any disagreement, dispute, controversy or claim arising out of or relating to this Agreement or the interpretation of this Agreement or any arrangements relating to this Agreement or contemplated in this Agreement or the breach, termination or invalidity thereof shall be settled by final and binding arbitration administered by JAMS/Endispute in San Diego, California in accordance with the then existing JAMS/Endispute Arbitration Rules and Procedures for Employment Disputes. In the event of such an arbitration proceeding, the Executive and the Company shall select a mutually acceptable neutral arbitrator from among the JAMS/Endispute panel of arbitrators. In the event the Executive and the Company cannot agree on an arbitrator, the Administrator of JAMS/Endispute will appoint an arbitrator. Neither the Executive nor the Company nor the arbitrator shall disclose the existence, content, or results of any arbitration hereunder without the prior written consent of all parties. Except as provided herein, the Federal Arbitration Act shall govern the interpretation, enforcement and all proceedings. The arbitrator shall apply the substantive law (and the law of remedies, if applicable) of the state of California, or federal law, or both, as applicable and the arbitrator is without jurisdiction to apply any different substantive law. The arbitrator shall have the authority to entertain a motion to dismiss and/or a motion for summary judgment by any party and shall apply the standards governing such motions under the Federal Rules of Civil Procedure. The arbitrator shall render an award and a written, reasoned opinion in support thereof. Judgment upon the award may be entered in any court having jurisdiction thereof." IN WITNESS WHEREOF, the Executive and, pursuant to authorization from its Board of Directors, the Company have caused this Amendment to Employment Agreement to be executed as of the effective date, above. SEMPRA ENERGY By: ________________________ Richard D. Farman Chairman & Chief Executive Officer ________________________ DONALD FELSINGER

Exhibit 10.04 AMENDMENT TO EMPLOYMENT AGREEMENT By this Agreement, Sempra Energy (the "Company"), a California corporation formerly known as Mineral Energy Company, and WARREN MITCHELL (the "Executive") amend the Employment Agreement (the "Agreement") between Mineral Energy Company and Executive dated October 12, 1996, to be effective December 1, 1998, as follows: 1. Paragraph 5 (a) (vi) of the Agreement is modified in its opening phrase to read: "(vi) Continuation of Welfare Benefits. For a period of three (3) years or until the Executive is eligible for retiree medical benefits, whichever is longer, ..." 2. Paragraphs 5 (d), (e) and (f) of the Agreement are stricken and replaced by the following: "(d) Code Section 280G (i) Gross-Up. Notwithstanding any other provisions of this Agreement, in the event that any payment or benefit received or to be received by the Executive (whether pursuant to the terms of this Agreement or any other plan, arrangement or agreement with (A) the Company, (B) any Person (as defined in Section 4(e))whose actions result in a Change in Control or (C) any Person affiliated with the Company or such Person) (all such payments and benefits, including the Severance Payments, being hereinafter called the "Total Payments") would be subject (in whole or part) to the tax (the "Excise Tax") imposed under section 4999 of the Code, the Company shall pay to the Executive such additional amounts (the "Gross-Up Payment") such that the net amount retained by the Executive, after deduction of any Excise Tax on the Total Payments and any federal, state and local income and employment taxes and Excise Tax upon the Gross-Up Payment, shall be equal to the Total Payments. For purposes of determining the amount of the Gross-Up Payment, the Executive shall be deemed to pay federal income tax at the highest marginal rate of federal income taxation in the calendar year in which the Gross-Up Payment is to be made and state and local income taxes at the highest marginal rate of taxation in the state and locality of the Executive's residence on the date on which the Gross-Up Payment is calculated for purposes of this section, net of the maximum reduction in federal income taxes which could be obtained from deduction of such state and local taxes. In the event that the Excise Tax is subsequently determined to be less than the amount taken into account hereunder, the Executive shall repay to the Company, at the time that the amount of such reduction in Excise Tax is finally determined, the portion of the Gross-Up Payment attributable to such reduction (plus that portion of the Gross-Up Payment attributable to the Excise Tax and federal, state and local income tax imposed on the Gross-Up Payment being repaid by the Executive to the extent that such repayment results in a reduction in Excise Tax and/or a federal, state or local income tax deduction) plus interest on the amount of such repayment at the rate provided in section 1274(b)(2)(B) of the Code. In the event that the Excise Tax is determined to exceed the amount taken into account hereunder (including by reason of any payment the existence or amount of which cannot be determined at the time of the Gross- Up Payment), the Company shall make an additional Gross-Up Payment in respect of such excess (plus any interest, penalties or additions payable by the Executive with respect to such excess) at the time that the amount of such excess is finally determined. The Executive and the Company shall each reasonably cooperate with the other in connection with any administrative or judicial proceedings concerning the existence or amount of liability for Excise Tax with respect to the Total Payments. (ii) Accounting Firm. All determinations to be made with respect to this Section 5 (d) shall be made by the Company's independent accounting firm (or, in the case of a payment following a Change in Control, the accounting firm that was, immediately prior to the Change in Control, the Company's independent auditor). The accounting firm shall be paid by the Company for its services performed hereunder." 3. Sections 5 (e) and (f) of the Agreement are added to read: "(e) Outplacement Services. The Executive shall receive outplacement services suitable to his or her position for a period of eighteen (18) months following the Date of Termination, or if earlier, until the first acceptance of an offer of employment with a subsequent employer, in an aggregate amount not to exceed $50,000. (f) Financial Planning Services. The Executive shall receive financial planning services for a period of eighteen (18) months following the Date of Termination at a level consistent with the benefits provided under the Company's financial planning program for the Executive, as in effect immediately prior to the Date of Termination." 4. Section 5(h) of the Agreement is added to read: (h) Notwithstanding anything contained herein, if a Change in Control occurs and if, prior to the date of the Change in Control, the Executive's employment is terminated by the Company (other than for Cause, death or Disability), or by the Executive for Good Reason, and if such Termination (i) was at the request of a third party who has taken steps reasonably calculated to effect the Change in Control or (ii) otherwise arose in connection with or in anticipation of the Change in Control, then such Termination shall be treated as a Termination following a Change in Control for purposes of this Agreement (including, without limitation, for purposes of determining the amounts of the Severance Payments under this Section 5). 5. Paragraph 8 ("Arbitration") of the Agreement is stricken and replaced with the following language: "8. Dispute Resolution. Any disagreement, dispute, controversy or claim arising out of or relating to this Agreement or the interpretation of this Agreement or any arrangements relating to this Agreement or contemplated in this Agreement or the breach, termination or invalidity thereof shall be settled by final and binding arbitration administered by JAMS/Endispute in San Diego, California in accordance with the then existing JAMS/Endispute Arbitration Rules and Procedures for Employment Disputes. In the event of such an arbitration proceeding, the Executive and the Company shall select a mutually acceptable neutral arbitrator from among the JAMS/Endispute panel of arbitrators. In the event the Executive and the Company cannot agree on an arbitrator, the Administrator of JAMS/Endispute will appoint an arbitrator. Neither the Executive nor the Company nor the arbitrator shall disclose the existence, content, or results of any arbitration hereunder without the prior written consent of all parties. Except as provided herein, the Federal Arbitration Act shall govern the interpretation, enforcement and all proceedings. The arbitrator shall apply the substantive law (and the law of remedies, if applicable) of the state of California, or federal law, or both, as applicable and the arbitrator is without jurisdiction to apply any different substantive law. The arbitrator shall have the authority to entertain a motion to dismiss and/or a motion for summary judgment by any party and shall apply the standards governing such motions under the Federal Rules of Civil Procedure. The arbitrator shall render an award and a written, reasoned opinion in support thereof. Judgment upon the award may be entered in any court having jurisdiction thereof." IN WITNESS WHEREOF, the Executive and, pursuant to authorization from its Board of Directors, the Company have caused this Amendment to Employment Agreement to be executed as of the effective date, above. SEMPRA ENERGY By: ________________________ Richard D. Farman Chairman & Chief Executive Officer ________________________ WARREN MITCHELL

Exhibit 10.09 SEMPRA ENERGY SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN This Supplemental Executive Retirement Plan provides retirement income, disability income and death benefits to key executives and their spouses under specified circumstances. This amended and restated Plan is effective July 1, 1998. TC "1. Definitions"\l SECTION 1 DEFINITIONS 1.1 "Actuarial Equivalent" means equivalent value when computed using the applicable mortality table promulgated by the IRS under Code Section 417(e)(3) as in effect on the first day of the Plan Year and the applicable interest rate promulgated by the IRS under Code Section 417(e)(3) for the November preceding the first day of the Plan Year. 1.2 "Average Bonus" means the average of the three highest annual incentive awards earned by a Participant under the Executive Incentive Plan during the Participant's last ten years of Service, determined an follows: (a) Annual incentive awards shall be counted whether or not deferred under the Deferred Compensation Plan. (b) If a Participant was designated as a participant in the Executive Incentive Plan for a year, but earned no annual incentive award during that year, the award will be counted as zero, and if the Participant did not earn three annual incentive awards during the other years during the last ten years of Service, the zero amount will be used to attain the average of the three highest annual incentive awards. (c) If the Participant was not designated as a participant in the Executive Incentive Plan for three full years of the last ten years of Service, the average shall be based on the number of full years the Participant was designated as a participant in the Executive Incentive Plan during the last ten years of Service. (d) As to a Participant in the Executive Incentive Plan who did not earn annual incentive awards during the last ten years of Service solely due to a disability which qualified him for a Basic Disability Plan Benefit, a Supplemental Disability Benefit or both, the applicable ten year period will be extended backwards for each year of such occurrence. (e) Prorated annual incentive awards earned under the Executive Incentive Plan will not be used in determining the average. (f) If a Participant works past his Normal Retirement Date, his "Average Bonus" will be determined and fixed as of such date. 1.3 "Average Earnings" means the average Earnings of the highest two years of Service in the last ten years while a Participant was not receiving a Basic Disability Plan Benefit, a Supplemental Disability Benefit or both. 1.4 "Basic Disability Plan" means a disability plan maintained by Sempra Energy or a subsidiary which provides coverage for most full time employees of the plan sponsor. 1.5 "Basic Disability Plan Benefit" means the annual amount of benefit payable from the Basic Disability Plan to a Participant. 1.6 "Basic Pension Plan" means the Sempra Energy Cash Balance Plan, and where applicable by the context, the pension plan of a subsidiary of Sempra Energy. 1.7 "Basic Pension Plan Benefit" means the annual amount of benefit payable from the Basic Pension Plan to a Participant on his Retirement Date in the form of a straight life annuity without a cost-of-living feature. 1.8 "Committee" means the Compensation Committee of the Company's Board of Directors. 1.9 "Company" means Sempra Energy. 1.10 "Deferred Compensation Plan" means the Sempra Energy Executive Deferred Compensation Plan. 1.11 "Earnings" means base compensation only including any deferral under the Savings Plan, the Supplemental Savings Plan and the Deferred Compensation Plan. 1.12 "Employer" means the Company and any of its subsidiaries (any corporation of which 50% or more of the issued and outstanding stock having ordinary voting rights is owned directly or indirectly by the Company or any other business entity or association of which 50% or more of the outstanding equity interest is so owned) which adopt this Plan. 1.13 "Employment" means employment by the Employer, including the period during which a Participant is receiving a Basic Disability Plan Benefit, and any additiona1 period during which a Participant is receiving a Supplemental Disability Benefit under this Plan. 1.14 "Executive Incentive Plan" means the Sempra Energy Executive Incentive Plan. 1.15 "Normal Retirement Date" means the first day of the month following the month in which a Participant attains age 65. 1.16 "Participant" means an employee of the Employer designated to participate in this Plan as specified in Section 2.1. 1.17 "Plan" means this Supplemental Executive Retirement Plan. 1.18 "Preretirement Spouse's Benefit" means the benefit payable or paid under the Basic Pension Plan and Excess Cash Balance Plan to a Surviving Spouse of a Participant who dies in Employment. 1.19 "Prior Plan" shall mean the Pacific Enterprises Supplemental Retirement and Survivor Plan and the San Diego Gas and Electric Supplemental Executive Retirement Plan. 1.20 "Retirement" means the termination of a Participant's Employment with the Employer after five years of Service on or after the Participant attains age 55. 1.21 "Retirement Date" means the first day of the month following a Participant's Retirement. 1.22 "Service" means a Participant's credited service which would be used to compute retirement benefits under the Basic Pension Plan. 1.23 "Social Security Benefit" means the annual Primary Insurance Amount estimated to be payable to the Participant at age 65 under the Federal Social Security Act in effect at the time of the event. 1.24 "Spouse's Supplemental Retirement Benefits" means the benefit payable to the Surviving Spouse of a Participant under Section 2.3 of this Plan after the Participant has died on or after his Retirement Date. 1.25 "Supplemental Disability Benefit" means the benefit payable to a disabled Participant under Section 2.5 of this Plan. 1.26 "Excess Cash Balance Plan" means the Sempra Energy Excess Cash Balance Plan, or any other supplemental pension plan of any Employer providing essentially the same benefits for one or more Participants. 1.27 "Excess Cash Balance Plan Benefits" means the annual amount of benefit payable or paid from the Excess Cash Balance Plan to a Participant on his Retirement Date in the form of a straight life annuity without a cost-of- living adjustment feature. 1.28 "Supplemental Retirement Benefit" means the benefit payable to a Participant under Section 2.2 of this Plan on his Retirement Date. 1.29 "Surviving Spouse" means in the case of a Spouse's Death Benefit, a spouse married to the Participant for at least the one-year period ending on the Participant's date of death, and means in the case of a Spouse's Supplemental Retirement Benefit, a spouse who is married to the Participant for at least the one-year period ending on the Participant's Retirement Date and who is still married to the Participant on the date of the Participant's death. Surviving Spouse also means a Spousal Equivalent as defined by the Company (subject to the one year requirements) under the Company Medical Plan. 1.30 The masculine pronoun whenever used shall include the feminine pronoun, and the singular shall include the plural where the context requires it. 1.31 "Vesting Factor" means the following for a Participant who qualifies for Retirement under paragraph 1.20 Vesting Schedule Age 55 56 57 58 59 60 and older Service 5 50% 60% 70% 80% 90% 100% 6 55% 60% 70% 80% 90% 100% 7 60% 65% 70% 80% 90% 100% 8 65% 70% 75% 80% 90% 100% 9 70% 75% 80% 85% 90% 100% 10 75% 80% 85% 90% 95% 100% 11 80% 85% 90% 95% 100% 100% 12 85% 90% 95% 100% 100% 100% 13 90% 95% 100% 100% 100% 100% 14 95% 100% 100% 100% 100% 100% 15 and more 100% 100% 100% 100% 100% 100% Based on attained age and completed years of service. TC "2. Eligibility for Benefits"\l SECTION 2 ELIGIBILITY FOR BENEFITS TC "2.1 Participation "\l2 2.1 Participation Executive Officers of the Company as designated shall be eligible to participate in this Plan. The Committee may designate additional officers and key employees of the Employer who shall participate in this Plan and the effective date of such participation, subject to agreement by the Board of Directors of the executive's Employer (if not the Company) that such executive participate and that such Employer pay the costs of this Plan for the executive and his Surviving Spouse. TC "2.2 Supplemental Retirement Benefit "\l2 2.2 Supplemental Retirement Benefit Each Participant is eligible to retire and receive a benefit under this Plan as specified in Sections 3.1 and 3.4 beginning on his Retirement Date. No Supplemental Retirement Benefit will be paid to a Participant who leaves Employment prior to attaining age 55 or completing five years of Service, except as provided under other agreements. TC "2.3 Spouse's Supplemental Retirement Benefit "\l2 2.3 Spouse's Supplemental Retirement Benefit The Surviving Spouse of a Participant who dies on or after his Retirement Date who did not receive a lump sum payment is eligible for a Spouse's Supplemental Retirement Benefit in accordance with Sections 3.2 and 3.4. TC "2.4 Spouse's Death Benefit "\l2 2.4 Spouse's Death Benefit The Surviving Spouse of a Participant who dies in Employment is eligible for a Spouse's Death Benefit as specified in Sections 4.1 and 4.2 in either the form of a lump sum benefit or lifetime annuity benefit as elected by the Participant. There is no cost to the Participant for this benefit. If a Participant dies during Employment without an eligible Surviving Spouse, no Spouse's Death Benefit is payable under this Plan. TC "2.5 Supplemental Disability Benefit "\l2 2.5 Supplemental Disability Benefit A Participant who becomes disabled may be eligible to receive a supplemental Disability Benefit as specified in Section 5. TC "3. Retirement Benefits "\l SECTION 3 RETIREMENT BENEFITS TC "3.1 Amount of Supplemental Retirement Benefit "\l2 3.1 Amount of Supplemental Retirement Benefit The annual Supplemental Retirement Benefit payable to a Participant as of his Retirement Date is equal to (a) minus (b) with the resultant product multiplied by the Participant's Vesting Factor and then the resultant product multiplied by the early retirement reduction (pursuant to Appendix A) for Retirement Dates which precede attainment of 62 years of age. The benefit will also be reduced as provided in Section 8: (a) is the sum of the following percent of the total of the Participant's Average Earnings and Average Bonus (i) 1/3% for each month of Service through 120 (40% for 10 years of Service), plus (ii) 1/6% for each month of Service in excess of 120, through 240 (60% for 20 years of Service), plus (iii) 1/48% for each month of Service in excess of 240 (65% for 40 years of Service). (b) is the sum of his (i) Basic Pension Plan Benefit, plus (ii) Excess Cash Balance Plan Benefit Provided however, that if a Participant commences receipt of benefits under this Plan on a different date than the Participant commences receipt of benefits under the Basic Pension Plan, this paragraph (b) shall be calculated based on the benefits the Participant would have received if the Participant elected the same Retirement Date under the Basic Pension Plan that he elected under this Plan. If (a) minus (b) results in zero or less, then no Supplemental Retirement Benefit is payable. The Participant may elect to receive the Supplemental Retirement Plan benefits, payable on his behalf, paid in an actuarially equivalent lump sum, provided the Participant elects such lump sum one year prior to retirement and submits evidence of good health satisfactory to the Committee. TC "3.2 Amount of Spouse's Supplemental Retirement Benefit "\l2 3.2 Amount of Spouse's Supplemental Retirement Benefit The annual Spouse's Supplemental Retirement Benefit payable to a Surviving Spouse of a Participant who did not receive a lump sum optional payment is equal to 50% of the Participant's Supplemental Retirement Benefit in Station 3.1(a) without the reduction in 3.1(b) but adjusted by the Vesting Factor and the early retirement reduction pursuant to appendix A. TC "3.3 Adjustments "\l2 3.3 Adjustments The annual Supplemental Retirement Benefit or the annual Spouse's Supplemental Retirement Benefit will not be decreased or increased on account of any increase or decrease in the Basic Pension Plan Benefit, Supplemental Pension Plan Benefit, or Social Security Benefit occurring after a Participant's Retirement Date or death. TC "3.4 Payment "\l2 3.4 Payment A Supplemental Retirement Benefit will be paid monthly, beginning on the last day of the month of the Participant's Retirement Date, and will continue to be paid monthly during the life of the Participant, the last payment to be made to the Participant's spouse, or if none, to the Participant's estate, on the last day of the month in which the death of the Participant occurs. If the Participant is survived by a Surviving Spouse, the Surviving Spouse will receive a Spouse's Supplemental Retirement Benefit. The Spouse's Supplemental Retirement Benefit will be paid monthly, and will commence on the last day of the month following the month in which the Participant dies and will continue during the life of the Surviving Spouse. The Participant may elect to receive all Supplemental Retirement Plan benefit payable on behalf of the Participant in an actuarially equivalent lump sum, provided the Participant elects one year prior to retirement and submits evidence satisfactory to the Committee of his/her good health. TC "4. Supplemental Preretirement Spouse's Death Benefits "\l SECTION 4 SUPPLEMENTAL PRERETIREMENT SPOUSE'S DEATH BENEFITS TC "4.1 Benefit "\l2 4.1 Benefit The annual Spouse's Death Benefit that will be paid to a Surviving Spouse of a Participant who dies in Employment prior to his Retirement Date is equal to (a) minus (b) when: (a) is 50% of the Participant's accrued benefit calculated in accordance with 3.1(a). If the Participant is under age 55 at the time of death, the age 55 early retirement factor shall be used, and (b) is the Surviving Spouse's Preretirement Spouse's Benefit, plus any life insurance benefit payable under any Split Dollar Life Insurance purchased in accordance with Section 8.1 herein. TC "4.2 Form of Benefit "\l2 4.2 Form of Benefit A Participant may elect to have his Surviving Spouse receive either the annuity benefit described above or, an Actuarially Equivalent lump sum payment. The payment of a lump sum requires that the election be made at least one year prior to the Participant's date of death and that the Surviving Spouse submits evidence satisfactory to the Committee of his/her good health. The initial election of benefit form must be made at the time of commencement of Participation. If a Participant wishes to change from the lump sum benefit to the lifetime annuity benefit or vice versa thereafter, the Participant may apply for such change as long as it is received by the Company in writing at least one year prior to termination under the Basic Plan. Spouse's Death Benefit shall automatically cease upon the earliest of: (i) the Participant's termination of Employment, (ii) the death of the Surviving Spouse, and (iii) the Participant's Retirement Date. TC "5. Supplemental Disability Benefits "\l SECTION 5 SUPPLEMENTAL DISABILITY BENEFITS TC "5.1 Amount "\l2 5.1 Amount The annual Supplemental Disability Benefit payable to a Participant is equal to (a) minus (b) when: (a) is 60% multiplied by the total of the Participant's Average Bonus and annual rate of Earnings in effect on the day immediately preceding the day the Participant becomes eligible, and (b) is the sum of (i) the Participant's Basic Disability Plan Benefit, and any other Company provided disability plan, plus (ii) the amount of benefits for which the Participant is eligible under the provisions of any federal or state law providing payments on account of disability, as these payments are defined in the Basic Disability Plan, during the period of eligibility for a Supplemental Disability Benefit. If (a) minus (b) results in zero or less, then no Supplemental Disability Benefit is payable. If the Basic Disability Plan Benefit increases under the Basic Disability Plan, the Supplemental Disability Benefit will be decreased by the same amount. TC "5.2 Payment "\l2 5.2 Payment Eligibility for a Supplemental Disability Benefit is determined by the Committee. The Supplemental Disability Benefit will be paid monthly. The last Supplemental Disability Benefit will be paid to the Participant at the earliest of (i) when the Committee deems that the Participant is no longer disabled, (ii) when Participant starts receiving a Supplemental Retirement Benefit, or (iii) when the Participant attains age 65. TC "6. Administration "\l SECTION 6 ADMINISTRATION TC "6.1 Authority of Committee "\l2 6.1 Authority of Committee This Plan shall be administered by the Committee. Subject to the express provisions of this Plan, the Committee shall have full and final authority to interpret this Plan, to prescribe, amend and rescind rules, regulations and guides relating to the Plan, and to make any other determinations that it believe. necessary or advisable for the administration of the Plan. The Committee may delegate certain responsibilities in the administration of the Plan. All decisions and determinations by the Committee shall be final and binding upon all parties. TC "6.2 Calculation of Benefits "\l2 6.2 Calculation of Benefits Any and all payments to be made under this Plan and all Actuarial Equivalents shall be calculated by the Company's regularly employed independent actuaries, and their determinations shall be final and binding on all parties. TC "7. Miscellaneous "\l SECTION 7 MISCELLANEOUS TC "7.1 Amendment, Termination or Removal of Participant "\l2 7.1 Amendment, Termination or Removal of Participant The Committee may, in its sole discretion, terminate, suspend, or amend this Plan at any time, in whole or in part. However, no amendment or suspension of the Plan will affect a retired or disabled Participant's right or the right of a Surviving Spouse to continue receiving a benefit in accordance with this Plan as in effect on the date such Participant or Surviving Spouse began to receive a benefit under this Plan. The Committee may, in its sole discretion, remove an executive as a Participant in this Plan due to changed job responsibilities or other changed circumstances as long as no benefits are then being paid to the Participant under this Plan. TC "7.2 No Employment Right "\l2 7.2 No Employment Right Nothing contained herein will confer upon any Participant the right to be retained in Employment, nor will it interfere with the right of his Employer to discharge or otherwise deal with the Participant without regard to the existence of this Plan. TC "7.3 Funding "\l2 7.3 Funding This Plan is unfunded, and the Employer will make Plan Benefit Payments solely on a current disbursement basis. Participants and their Beneficiaries shall have no legal or equitable rights, claims, or interest in any specific property or assets of the Employer, and the rights of the Participants and Beneficiaries shall be no greater than those of unsecured general creditors. TC "7.4 Allocation of Costs "\l2 7.4 Allocation of Costs Amounts accrued as expenses under this Plan, and the cost of any life insurance policies purchased to fund for benefits payable under this Plan, shall be allocated to Employers whose employees are Participants in this Plan. TC "7.5 Nonassignment "\l2 7.5 Nonassignment To the maximum extent permitted by law, no benefit under this Plan will be assignable or subject in any manner to alienation, sale, transfer, claims of creditors, pledge, attachment, or encumbrances of any kind. TC "7.6 Governing Law "\l2 7.6 Governing Law This Plan is established under and will be construed according to the laws of the State of California. TC "8. Offset for Certain Benefits Payable Under Split-Dollar Life Insurance "\l SECTION 8 OFFSET FOR CERTAIN BENEFITS PAYABLE UNDER OTHER PLANS 8.1 Some of the Participants under this Plan own life insurance policies (the "Policies") purchased on their behalf by the Company. The ownership of these Policies by each Participant is, however, subject to certain conditions (set forth in a "Split Dollar Life Insurance Agreement" or other comparable agreements between the Participant and the Company) and, if the Participant fails to meet the conditions set forth in the Split Dollar Life Insurance Agreement, the Participant may lose certain rights under the Policy. In the event that a Participant satisfies the conditions specified in Section 5 or 6 of the Split Dollar Life Insurance Agreement, so that the Participant or his beneficiary becomes entitled to benefits under one of those sections, the value of those benefits shall constitute an offset to any benefits otherwise payable under this Plan. As the case may be, this offset (the "Offset Value") shall be calculated by determining the value of benefits payable under the Split Dollar Life Insurance Agreement, that is, the cash surrender value of the Policy, or in the case of the Participant's death, the death benefits payable to the beneficiary under the Policy. The Offset Value shall then be compared to the Actuarial Equivalent (as defined in Section 8.4) of the benefits payable under this Plan (the "Plan Values), and the Plan Value shall be reduced by the Offset Value. 8.2 At the time when the Participant terminates employment for any reason, if the Plan Value exceeds the present value (determined using the interest rate specified in Section 8.4) of the Offset Value, the excess of the Plan Value over the present value of the Offset Value shall be paid to the Participant or beneficiary at that time in a lump sum. Provided that the Participant or beneficiary submits evidence satisfactory to the Committee of his/her good health. If the Participant is not in good health, the benefits will be paid as an annuity. The Participant may choose, one year prior to the date of termination, to receive the remaining amount as an annuity. Such payment shall completely discharge all obligations owed under this Plan on account of Participant's participation in this Plan. 8.3 If the Policy described in Section 8.1 is not on the life of the Participant, the insured dies prior to the Participant becoming eligible for benefits under the Plan, and the Participant or the Participant's beneficiary subsequently becomes eligible for benefits hereunder, the Actuarial Equivalent of the benefits payable hereunder shall be offset by the Actuarial Equivalent of the payments previously paid to the Participant in the Split Dollar Life Insurance Agreement. Any remaining amount due the Participant or the Participant's beneficiary shall thereupon be paid in a cash lump sum, provided that the Participant or beneficiary submits evidence satisfactory to the Committee of his/her good health. If the Participant is not in good health, the benefits will be paid as an annuity. The Participant may choose, one year prior to the date of termination, to receive the remaining amount as an annuity. 8.4 Notwithstanding anything contained herein to the contrary, in the event that a Participant has a benefit under Excess Cash Balance Plan, the Offset Value shall first be applied to reduce benefits paid under the Excess Cash Balance Plan and any remaining Offset Value shall then be applied to reduce the Plan Value under this Plan; provided, however, that for purposes of determining the amount of benefits payable under this Plan, any benefits payable under the Excess Cash Balance Plan shall be determined without regard to such offset. 8.5 The Committee may offer additional options which are of equivalent value. APPENDIX A EARLY RETIREMENT REDUCTION FACTOR Age 62 and later 61 60 59 58 57 56 55 Early Retirement Factor* 100% 97% 94% 90% 86% 82% 78% 74% *Reduction factors vary by age and months. APPENDIX B GRANDFATHER BENEFIT Current Participants in the Prior Plans are permanently grandfathered under the Prior Plan provisions if the benefit is greater. SEMPRA ENERGY SUPPLEMENTAL EXECUTIVE RETIREMENT PLAN Section Page TOC \f \* MERGEFORMAT 1. Definitions GOTOBUTTON _Toc416840980 PAGEREF _Toc416840980 2. Eligibility for Benefits GOTOBUTTON _Toc416840981 PAGEREF _Toc416840981 2.1 Participation GOTOBUTTON _Toc416840982 PAGEREF _Toc416840982 2.2 Supplemental Retirement Benefit GOTOBUTTON _Toc416840983 PAGEREF _Toc416840983 2.3 Spouse's Supplemental Retirement Benefit GOTOBUTTON _Toc416840984 PAGEREF _Toc416840984 2.4 Spouse's Death Benefit GOTOBUTTON _Toc416840985 PAGEREF _Toc416840985 2.5 Supplemental Disability Benefit GOTOBUTTON _Toc416840986 PAGEREF _Toc416840986 3. Retirement Benefits GOTOBUTTON _Toc416840987 PAGEREF _Toc416840987 3.1 Amount of Supplemental Retirement Benefit GOTOBUTTON _Toc416840988 PAGEREF _Toc416840988 3.2 Amount of Spouse's Supplemental Retirement Benefit GOTOBUTTON _Toc416840989 PAGEREF _Toc416840989 3.3 Adjustments GOTOBUTTON _Toc416840990 PAGEREF _Toc416840990 3.4 Payment GOTOBUTTON _Toc416840991 PAGEREF _Toc416840991 4. Supplemental Preretirement Spouse's Death Benefits GOTOBUTTON _Toc416840992 PAGEREF _Toc416840992 4.1 Benefit GOTOBUTTON _Toc416840993 PAGEREF _Toc416840993 4.2 Form of Benefit GOTOBUTTON _Toc416840994 PAGEREF _Toc416840994 5. Supplemental Disability Benefits GOTOBUTTON _Toc416840995 PAGEREF _Toc416840995 5.1 Amount GOTOBUTTON _Toc416840996 PAGEREF _Toc416840996 5.2 Payment GOTOBUTTON _Toc416840997 PAGEREF _Toc416840997 6. Administration GOTOBUTTON _Toc416840998 PAGEREF _Toc416840998 6.1 Authority of Committee GOTOBUTTON _Toc416840999 PAGEREF _Toc416840999 6.2 Calculation of Benefits GOTOBUTTON _Toc416841000 PAGEREF _Toc416841000 7. Miscellaneous GOTOBUTTON _Toc416841001 PAGEREF _Toc416841001 7.1 Amendment, Termination or Removal of Participant GOTOBUTTON _Toc416841002 PAGEREF _Toc416841002 7.2 No Employment Right GOTOBUTTON _Toc416841003 PAGEREF _Toc416841003 7.3 Funding GOTOBUTTON _Toc416841004 PAGEREF _Toc416841004 7.4 Allocation of Costs GOTOBUTTON _Toc416841005 PAGEREF _Toc416841005 7.5 Nonassignment GOTOBUTTON _Toc416841006 PAGEREF _Toc416841006 7.6 Governing Law GOTOBUTTON _Toc416841007 PAGEREF _Toc416841007 8. Offset for Certain Benefits Payable Under Split-Dollar Life Insurance GOTOBUTTON _Toc416841008 PAGEREF _Toc416841008 APPENDIX A APPENDIX B

Exhibit 10.10 SEMPRA ENERGY DEFERRED COMPENSATION PLAN FOR DIRECTORS I. Purpose The purpose of this Plan is to enhance the ability of Sempra Energy to attract and retain outstanding members to serve on its Board of Directors. II. Definitions A. "Account" means each separate unfunded booking account established for a Participant under Paragraph A of Article V. B. "Beneficiary" means the person or persons or entity or entities designated by a Participant to receive the benefits payable to a Beneficiary in accordance with Article IX of the Plan after the Participant's death. C. "Committee" means the Compensation Committee of the Company's Board of Directors. D. "Company" means Sempra Energy. E. "Compensation" means all compensation earned for services as a Director, including retainer payments and meeting and other fees. F. "Eligible Director" means each member of the Company's Board of Directors who is not an employee of the Company. G. "Fixed Account" means the investment option that provides a fixed rate of return tied to the Moody's Rate. H. "Investment Return" means the actual earnings or loss under any of the investment options, other than the fixed return option, made available to the Participant. I. "Moody's Plus Rate" means the Moody's Rate as defined below plus the greater of (1) 10% of the Moody's Rate or (2) one percentage point per annum. Moody's Rate is the Moody's Corporate Bond Yield Average - Monthly Average Corporates as published by Moody's Investors Service, Inc. (or any successor thereto). The Moody's Rate for the month of June, as used in this Plan, means the average of the daily Moody's Rates for June. J. "Participant" means an Eligible Director who has elected to defer compensation pursuant to Article III. K. "Plan" means this Deferred Compensation Plan for Directors. L. "Plan Year" means a payroll calendar year except that the first Plan Year shall be from July 1, 1998 through December 31, 1998. M. "Surviving Spouse" means a Participant's spouse married to the Participant on the Participant's date of death and still living on the date benefits are payable to a Surviving Spouse under Paragraph B of Article IX of the Plan. N. The masculine pronoun whenever used shall include the feminine pronoun, and the singular shall include the plural, as the context requires. III. Participation Election to Participate Each Eligible Director shall become a Participant in the Plan by electing to defer all or any portion of his Compensation in accordance with Article IV of this Plan. Each Eligible Director shall remain a Participant in the Plan, whether or not eligible to continue deferring Compensation until all amounts credited to his Account have been distributed or until his death, if earlier. IV. Deferral A. Amount of Deferral An Eligible Director may elect to defer 100% or any smaller percentage of his Compensation payable during a Plan Year. The amount of Compensation deferred shall be withheld on the date or dates it otherwise would be payable to the Participant. B. Election to Defer An election to defer shall be made before the beginning of the Plan Year during which Compensation is to be earned. Election shall be in writing, shall be modified only by adjustments permitted under the Plan, shall be made at the time and in the form prescribed by the Company, and shall be effective only upon delivery to the Company. The election shall specify the amount deferred, the deferral period, the payment method and any other matter required to be specified by the Company. C. Adjustments and Special Deferral Elections Notwithstanding the above, in the event an individual first becomes an Eligible Director during any Plan Year for which the Company permits deferrals of Compensation, the Eligible Director may elect to defer Compensation thereafter payable, as permitted by the Company in its sole and absolute discretion. Such an election must be made by the date specified by the Company, and for Compensation payable during the Plan Year of initial eligibility, within 30 days of the date the individual first becomes an Eligible Director, and for Compensation payable during any subsequent Plan Year, before the start of the Plan Year. A Participant may modify his/her deferral election in the event that there is a change in a Participant's marital status or number of Dependents or there is a termination or commencement of employment of the Participant's spouse. A Participant shall be entitled to change his deferral election in a manner that is consistent with such change in marital, dependent, or employment status, by providing written notice thereof to the Company, in a form acceptable to the Company. Any such change shall be effective on the first day of the calendar month next coincident to the month in which written notice is received by the Company. V. Accounts A. Participants' Accounts For deferrals permitted by the Company and elected by a Participant a separate Account or Accounts shall be established as specified by the Company for each Plan Year. Each Account shall be treated separately for purposes of payment of benefits under the Plan. Compensation shall be credited to each Account as of the date they otherwise would have been paid to the Participant. The deferral shall be invested in the Fixed Account or as permitted by the Company, to purchase Company stock, or other equity securities. All such purchases must be made through an investment tracking device, a Rabbi Trust, or other similar instrument that causes the deferred amount not to become taxable to the Participant. All such purchases must be made in accordance with applicable Company procedures as they may be amended from time to time. The Company may permit funds in one investment option to be transferred to other investment options. B. Interest Credited on Deferrals Interest shall be credited to each Account invested in the Fixed Account during each Plan Year at a rate equal to the Moody's Plus Rate for the month of June immediately prior to the Plan Year in which such interest rate is to be credited. The interest rate credited to Participants' Accounts may fluctuate from Plan Year to Plan Year. However, when distribution is to begin as to a Participant's Account, and the Participant has elected installment payments, the rate shall be fixed on the date installment payments are to begin. The fixed rate shall be the average of the Moody's Plus Rates for the June of the five prior calendar years, and that rate thereafter shall be credited to the Participant's Account from which the installment payments are to be made. Interest on each Account balance shall be credited monthly at one-twelfth the appropriate rate, compounded monthly. C. Investment Return Credited on Deferral in Other Investment Option The investment return credited to each Account during each Plan Year shall be the actual return earned or lost on the investment option. VI. Length of Deferral A. Basic Deferral Period At the time of electing deferral, a Participant shall select the period of deferral from the deferral periods specified by the Company on its prescribed election form. The period of deferral shall end, and distribution from the Participant's Account shall begin at the earliest of the Participant's death, retirement, or other separation from the Company's Board of Directors, unless the Company offers and the Participant selects some other deferral period B. In-Service Distributions 1. Fixed Term Election A Participant may elect to receive an in service distribution on such date and upon such other terms as the Company specifies at the time of the Participant's deferral election provided that no fixed term election shall be for a period of less than five years. Each in service distribution shall equal the amount in the account for the Plan Year for which the in service distribution is elected Amounts remaining in the Participant's Account thereafter shall continue to accrue interest or Investment Return as the case may be. 2. Unplanned Early Distribution Notwithstanding any other provisions of the Plan, by a written request filed with the Committee, a Participant, may elect to receive an immediate lump sum payment equal to the amount or a percentage of the amount deferred, or the actual amount in the Account reduced by a penalty, which shall be forfeited to the Plan, equal to ten percent (10%) of the deferrals withdrawn in lieu of payments in accordance with the form previously elected by the Participant. The Amount remaining in the Participant's Account shall continue to earn credited interest or Investment Return. A participant electing such an early in service distribution shall be ineligible to make deferrals for the two succeeding Plan Years. C. Hardship Withdrawal If a Participant suffers an extreme financial hardship, the Committee, in its sole and absolute discretion and upon the Participant's written application, will determine whether to permit withdrawal from the Participant's Account or Accounts. Any withdrawal that is permitted shall not exceed the amount of Compensation deferred by the Participant exclusive of credited interest or the actual amount in the Account, if less. Requests for withdrawals are expected to be unusual, and the Committee will make all determinations regarding extreme financial hardship in a uniform, nondiscriminatory manner. The term "extreme financial hardship" shall mean a severe financial hardship to the Participant resulting from a sudden and unexpected illness or accident of the Participant or of a dependent (as defined in Section 152(A) of the Internal Revenue Code) of the Participant, loss of the Participant's property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant. The circumstances that will constitute an extreme financial hardship will depend upon the facts of each case, but, in any case, payment may not be made to the extent that such hardship is or may be relieved (1) through reimbursement or compensation by insurance or otherwise, (2) by liquidation of the Participant's assets, to the extent the liquidation of such assets would not itself cause severe financial hardship, or (3) by cessation of deferrals under the Plan. Examples of what are not considered to be extreme financial hardships include the need to send a Participant's child to college or the desire to purchase a home. VII. Method of Distribution General Distribution Election Definitions Any amount a Participant elects to receive as an in service distribution shall be paid to the Participant in a single lump sum, or in such other optional form of payment as the Company may offer and the Participant may elect at the time of his deferral election. Distribution of all other amounts credited to each Account of a Participant shall be made, as specified by the Participant at the time of electing deferral of the Compensation credited to the Account. The distribution election may be modified if, and only if, a written change of distribution election form is received by the Company no less than 12 months prior to the Participant's retirement or other separation from service on the Board of Directors. As elected by the Participant, distribution shall be in fifteen, ten or five approximately equal annual installments or in lump sum, or in such other payment form as offered by the Company and elected by the Participant at the time of electing deferral, except as otherwise provided in Article VIII and Article IX. In the case of installment payments, all Participant account balances will be transferred to the Fixed Account. Interest at the fixed rate specified in Paragraph B of Article V shall be credited on all amounts remaining in the Participant's Account from which the installment payments are to be made. Notwithstanding anything in this Plan to the contrary, any payment made to a Participant or to his Beneficiary shall be according to the Participant's election after the distribution event that entitles the Participant or Beneficiary to such payment. VIII. Benefits on Death Distribution of benefits from each Account of a Participant shall begin as soon as practicable following the Participant's death in accordance with Paragraph A or B below, depending on whether the Participant dies before or after beginning to receive benefits from the Account. Each Account of a Participant shall be treated separately. A. Before Payments Have Begun If a Participant dies before payment from an Account has begun, other than any in service distributions made under Paragraph B(2) of Article VI, the Participant's Beneficiary will receive payment of the Participant's Account as soon as practicable after the Participant's death, as if the Participant had started to receive payment from the Account one day prior to his death. Payment to the Beneficiary shall be made in the same payment method as elected by the Participant, whether over fifteen, ten or five years, or in lump sum, or as otherwise permitted by the Company and elected by the Participant at the time of his deferral election or by subsequent election as permitted by the Plan. B. After Payments Have Begun If a Participant dies after beginning to receive payment from an Account, other than any in service distributions made under Paragraph B(2) of Article VI, the Participant's Beneficiary shall receive the remaining payments to be made from the Account if any. C. Designation of Beneficiary A Participant shall, as a condition of the right to make deferrals, designate a Beneficiary to receive the distributions described in Paragraph A or B above, whichever is applicable, following his death. Beneficiary designations shall be on the form prescribed by the Company for this purpose and shall only be effective upon delivery to the Company before the Participant's death. If a Participant designates a Beneficiary other than his spouse, his spouse's written consent to such designation must be obtained on the prescribed Beneficiary designation form. A Participant may change his Beneficiary from time to time by delivering a new designation form to the Company. If there is no designated beneficiary living at the time of a Participant's death, the estate of the deceased Participant shall be the Beneficiary. After a Participant's death, a designated Beneficiary who is to receive installment payments (not the Participant's estate) may designate a secondary beneficiary to receive any amounts due under this Plan to the Beneficiary in the event of the death of the Participant's designated Beneficiary prior to full payment to the Beneficiary. If there is no designated secondary beneficiary living at the time of death of the Participant's designated Beneficiary and installment payments remain to be paid to the Participant's Beneficiary, the estate of the Participant's designated Beneficiary shall be the beneficiary of any distributions due to the Participant's designated Beneficiary under the Plan. D. Cash Out of Small Amounts Following a Participant's death, the Company shall distribute all amounts remaining in the Participant's Account if less than $10,000, but such cash-out shall not affect the timing or the amount of benefits payable under Paragraph B above. E. Modification of Payment Method Notwithstanding any other provisions of the Plan, by a written request filed with the Committee, a retired Participant, or Beneficiary of a deceased Participant receiving benefits from the decedents Deferral Account(s), may elect to receive an immediate lump sum payment of the balance of his Deferral Account(s), reduced by a penalty, which shall be forfeited to the Plan, equal to ten percent (10%) of the balance of such Account(s), in lieu of payments in accordance with the form previously elected by the Participant. IX. Administration This Plan shall be administered by the Committee. Subject to the express provisions of this Plan, the Committee shall have full and final authority to interpret the Plan, to prescribe, amend and rescind rules, regulations and guidelines relating to the Plan, and to make any other determinations it believes necessary or advisable for the administration of the Plan. All decisions and determinations by the Committee shall be final and binding upon all parties. No member of the Committee who is also a Participant in this Plan shall decide or vote on any matter that would affect such Participant in a manner materially different from other Participants. The Company's Senior Human Resources Officer shall have discretionary authority with respect to administrative matters relating to this Plan, except when exercise of such authority would materially affect the cost of the Plan to the Employer or materially increase benefits to Participants. X. Amendment or Termination of the Plan The Committee may, in its sole discretion, suspend, amend or terminate this Plan at any time, in whole or in part. However, such action shall be prospective only and shall not adversely affect the rights of any Participant, Beneficiary or Surviving Spouse to any amounts previously credited to a Participant's Account or Accounts under the Plan. The Committee may increase or decrease the interest rate credited to Participants' Fixed Accounts including Compensation previously deferred, but the rate shall not be decreased for periods prior to such action. Any termination of the Plan shall not result in automatic payment of Accounts, and Participants' Accounts shall be paid under the terms of the Plan as in effect prior to termination. However, in the event a final determination is made by a court of competent jurisdiction, or by the relevant tax authorities, and no appeal is taken therefrom, that amounts deferred under this Plan are taxable income to a Participant prior to the time they otherwise would be distributed under the Plan, the Committee may terminate the Plan as to such Participant and immediately pay to him, or on his death to his Beneficiary, all amounts that are so taxable. XI. Miscellaneous A. Insurance As a condition of participation in this Plan, each Participant shall, if requested by the Company, undergo such examination and provide such information as may be required by the Company with respect to any insurance contracts on the Participant's life, and shall authorize the Company to purchase life insurance on his life, payable to the Company. If an insurance policy is invalidated because a Participant commits suicide during the two-year period beginning on the first day of the first Plan Year of such Participant's participation in the Plan, or if the Participant makes any material misstatement of information or nondisclosure of medical history, then no benefits will be payable hereunder to such Participant, his Beneficiary or his Surviving Spouse, other than payment of the amount of deferrals of Compensation then credited to the Participant's Accounts, without any interest, including interest theretofore credited under this Plan. B. Source of Payment This Plan is unfunded, and distributions shall be made solely on a current disbursement basis. Each Participant, his Beneficiary and his Surviving Spouse shall be no more than unsecured general creditors of the Company, and nothing contained in this Plan shall be deemed to create a trust of any kind, for the benefit of any Participant, Beneficiary or Surviving Spouse, or create any fiduciary relationship between the Company and any Participant, Beneficiary, or Surviving Spouse with respect to any assets of the Company, including, but not limited to, any insurance policies which the Company may purchase on the life of the Participant. The Company, however, retains the right to establish reserves for the obligations hereunder including, but not limited to corporate owned life insurance, and assets held in a "Rabbi Trust." Provided that in the event that the Chief Executive Officer determines that a change in control as defined in the Sempra Energy Long Term Incentive Plan, is imminent then assets shall be placed in the Key Employee and Director Deferred Compensation Trust Agreement which when combined with any assets then in the trust shall equal the full accrued liability under this Plan as determined by Towers and Perrin, or a successor actuarial firm. C. Withholding Each Participant, Beneficiary and Surviving Spouse to whom distribution is made shall make appropriate arrangements for the satisfaction of any federal, state, or local income tax withholding requirements, any social security or other employment tax requirements applicable to the payment of benefits under this Plan, and any payments the Participant agreed to make to the Company or to his Employer. If no other arrangements are made, the Company may provide, at its discretion, for such withholding and tax payments as may be required. D. Nonassignment To the maximum extent permitted by law, no benefit under this Plan shall be assignable or subject in any manner to alienation, sale, transfer, claims of creditors, pledge, attachment or encumbrances of any kind. E. Governing Law This Plan is established under and will be construed according to the laws of the State of California to the extent that such laws are not preempted by the Employee Retirement Income Security Act of 1974, as amended. F. Effective Date This Plan is effective June 1, 1998 SEMPRA ENERGY DEFERRED COMPENSATION PLAN FOR DIRECTORS (Effective June 1, 1998) Contents I. Purpose 1 II. Definitions 1 III. Participation 3 IV. Deferral 3 A. Amount of Deferral 3 B. Election to Defer 3 C. Adjustments and Special Deferred Elections 4 V. Accounts 5 A. Participants' Accounts 5 B. Interest Credited on Deferrals 6 C. Investment Return Credited on Deferral in Other Investment Option 6 VI. Length of Deferral 7 A. Basic Deferral Period 7 B. In-Service Distributions 7 1. Fixed Term Election 7 2. Unplanned Early Distribution 8 C. Hardship Withdrawal 8 VII. Method of Distribution 9 General Distribution Election Definitions 9 VIII. Benefits on Death 11 A. Before Payments Have Begun 11 B. After Payments Have Begun 11 C. Designation of Beneficiary 12 D. Cash Out of Small Amounts 13 E. Modification of Payment Method 13 IX. Administration 13 X. Amendment or Termination of the Plan 14 XI. Miscellaneous 15 A. No Employment Right 15 B. Insurance 16 C. Source of Payment 17 D. Withholding 17 E. Nonassignment 17 F. Governing Law 17 G. Effective Date 17 - -ii- vi

Exhibit 10.11 SEMPRA ENERGY EXECUTIVE INCENTIVE PLAN 1. Purpose The purpose of this Plan, which is an unfunded plan, is to foster attainment of the financial and strategic objectives of Sempra Energy (the "Company") by providing incentive to senior officers who contribute to the attainment of these objectives. 2. Administration The Plan shall be administered jointly by the Compensation Committee of the Company's Board of Directors and as to any employee of a Subsidiary, the Compensation Committee, if any, of the board of directors of such Subsidiary (collectively referred to as the "Committee"). Subject to the provisions of the Plan, the Committee shall have full and final authority to select participants, to designate the award potential of each participant, to determine performance objectives and to determine the amount and form of awards. The Committee shall also have, subject to the provisions of the Plan, full and final authority to interpret the Plan, to establish and revise rules, regulations and guides relating to the Plan, and to make any other determinations that it believes necessary or advisable for the administration of the Plan. The Committee may delegate its responsibilities, (other than the responsibility to select the participants, establish performance goals, determine incentive periods, establish award potentials for each participant, certify whether the performance goals are met), to the Chief Executive Officer of the Company ("Chief Executive Officer") or to any other officer of the Company. All decisions and determinations by the Committee shall be final and binding upon all parties, including shareholders, participants and other employees. The Committee shall have sole discretion as to whether to suspend operation of the Plan for any period of time. 3. Participation Senior Officers of the Company or any of its Subsidiaries as designated who, through their position and performance, have the opportunity to contribute substantially to the attainment of the financial objectives of the Company are eligible for selection to participate in this Plan. A Subsidiary for this purpose is any corporation of which 50 percent or more of the issued and outstanding stock having ordinary voting rights is owned directly or indirectly by the Company, or any other business entity or association of which 50 percent or more of the outstanding equity interest is so owned. Members of the Board of Directors of the Company or any Subsidiary, who are not officers of the Company or its Subsidiaries, are ineligible to participate in the Plan. No member of the Committee shall be eligible to participate. 4. INCENTIVE AWARDS a. Annual Awards If the Committee determines that participants shall be eligible to earn awards over a fiscal year ("award period"), it shall, no later than 90 days after the commencement of that award period select from the eligible participant group those participants who are eligible to receive awards for that award period and approve in writing threshold, target and maximum performance goals for that year for the Company, any Subsidiary employing a selected participant and/or any Business Unit for which a selected participant has substantial duties and responsibilities. For this purpose, a Business Unit means a division, department or other business segment which is part of the Company or of a Subsidiary. The Committee may also select an award period of 12 months other than a fiscal year or an award period either longer or shorter than 12 months in duration but only one award period may be in operation at any time in respect to any particular employee. In the event that an award period of less than 12 months is selected, the Committee shall select the participants and the financial goals before the expiration of 25% of such award period. Performance goals shall be limited to one or more of the following: (i) net revenue; (ii) net earnings; (iii) operating earnings or income; (iv) absolute and/or relative return on equity or assets; (v) earnings per share; (vi) cash flow; (vii) pretax profits; (viii) earnings growth; (ix) revenue growth; (x) book value per share; (xi) stock price; (xii) economic value added; (xiii) total shareholder return; (xiv) operating goals (including, but not limited to, safety, reliability, maintenance expenses, capital expenses, customer satisfaction and employee satisfaction); and (xv) performance relative to peer companies, each of which may be established on a corporate-wide basis or established with respect to one or more operating units, divisions, acquired businesses, minority investments, partnerships or joint ventures. At the same time that the Committee approves the performance goals, the Committee shall approve in writing a threshold, target and maximum award for each participant. Each participant's award shall be based upon the responsibility of the participant's position and its prospective contribution to the Company's or Subsidiary's, attainment of performance objectives. If the performance is somewhere between the threshold and target, or target and maximum performance goals, a participant's award shall be mathematically interpolated on a linear basis between threshold award and target award or between target award and maximum award. b. Incentive periods of less duration than the award period. During an award period, the Committee may select additional employees for participation, as it deems appropriate, who have been first employed or had a change in employment responsibilities since the beginning of the award period provided that the outcome of the selected performance goal for that award period for the Company, Subsidiary or Business Unit employing such employee remains substantially uncertain at that time. In this event, the incentive period shall begin with the first day of employment or change in employment responsibilities and end with the close of that award period. If the employee was already a participant in this plan prior to the change in employment responsibilities, the employee's award potential for the period of service prior to the change in employment responsibilities shall be prorated based on the ratio that the prior period of service bears to the applicable award period. Prior to the expiration of 25% of the applicable period of service for that incentive period and while the outcome of the selected performance goal is still substantially uncertain, the Committee shall approve in writing a threshold, target and maximum award for that participant depending on whether the threshold, target or maximum performance goal for the award period is achieved and a maximum dollar amount (which may not exceed $3,000,000 for the purpose of qualifying under 162(m) provisions) that can be paid to each participant under this plan for the incentive period. In the event that no performance goal has been previously selected for that award period for the Company, Subsidiary or Business Unit employing the participant, the Committee shall also establish in writing threshold, target and maximum performance goals for that year for that entity from the factors listed in section 4a of this plan. The outcome of the goals selected must be substantially uncertain. If the performance is somewhere between the threshold and target, or target and maximum performance goals, a participant's award shall be mathematically interpolated on a linear basis between the threshold and target award or between the target and maximum award. c. Certification and Payments of Award As soon as practicable after the end of an award period or incentive period the Committee shall certify in writing the extent to which the performance goals have been met and determine the amount, if any, of each participant's award before payment of the award. All awards under the plan are contingent upon the material terms of the performance goals being submitted to and approved by the shareholders. 5. Award Payment or Deferral As soon as practicable after the Committee has approved the award amounts for an award period or incentive period, payment shall be made to each participant in cash or in stock or in a combination of cash and stock, unless the participant has elected to defer the receipt of his award. Any deferral by a participant of an annual incentive award otherwise payable in cash under this Plan shall be pursuant to the Sempra Energy Corporation Executive Deferred Compensation Plan . Provided however, that if the maximum deductible compensation limits of IRS Code Section 162(m) are exceeded then such deferral as may be necessary to avoid such limitation, shall be mandatory for the participants at the discretion of the Compensation Committee. 6. Termination If the employment of a participant by the Company and its subsidiaries is terminated by the participant's death, long term disability or retirement under the pension plan of the Company or a subsidiary, the Committee shall prorate an award for the award period or incentive period in which the employee was participating prior to such termination, and the Company shall pay the prorated award at the same time as for other participants. In the case of a participant's death, payment of all amounts due under this Plan shall be made to the estate. A participant who has been determined to be eligible for supplemental disability payments under the terms of the Supplemental Executive Retirement Plan, and who has received at least 6 months of payments, shall be deemed to be terminated due to such disability for purposes of this Plan. If termination occurs because of unsatisfactory performance or for cause, as determined in the sole discretion of the Committee then there will be no award for the year of termination. If the employment of a participant is terminated for any other reason, the participant may receive a prorated award for any award period or incentive periods in which the participant was participating at the time of termination, as determined by the Committee in its sole discretion. If a participant does not work during an award period or incentive period for any period of time and for any reason and yet is entitled to an award under this Plan for participation during such award period or incentive period, the Committee may reduce or eliminate the participant's award because of the inactive period in such manner as it, in its sole discretion, deems just and reasonable. The Committee also retains the discretion to terminate the participation of any participant during an award period or incentive period if the Committee determines, in the Committee's sole discretion, that the participant is not contributing substantially to the attainment of the performance objectives of the Company and that such termination of participation is just and reasonable under the circumstances. In the event of such termination, the participant will be entitled to no award for that award period or incentive period. 7. Miscellaneous Provisions a. No Employment Right Neither this Plan nor any action taken hereunder shall be construed as giving any employee any right to be retained in the employ of the Company or any of its subsidiaries or interfere in any way with the right of the Company or any of its subsidiaries to determine a participant's compensation or any other term of employment. b. Non-transferability A participant's rights and interests under this Plan may not be assigned, transferred, attached or hypothecated. c. Withholding The participant's employer shall have the right to deduct from any payment any sums required to be withheld by federal, state, or local tax law. There is no obligation hereunder that any participants or other person be advised in advance of the existence of the tax or the amount so required to be withheld. 8. Amendment and Termination The Board of Directors of the Company may at any time, suspend, amend, modify or terminate this Plan provided that no such suspension, amendment, modification or termination shall alter or impair any rights or obligations to any award made previously under this Plan. The Committee may, in its sole discretion, terminate an award period and any associated incentive periods at any time. In this event, any potential awards for that award period or incentive period shall be prorated to the time of termination. 9. Effective Date This Plan shall be effective as of June 1, 1998.

Exhibit 10.12 SEMPRA ENERGY EXECUTIVE DEFERRED COMPENSATION PLAN I. Purpose The purpose of this Plan is to provide the opportunity to defer the receipt of compensation to a select group of executives upon whose judgment, initiative and efforts the continued success of the Sempra Energy Companies is dependent. II. Definitions A. "Account" means each separate unfunded booking account established for a Participant under Paragraph A of Article V. B. "Beneficiary" means the person or persons or entity or entities designated by a Participant to receive the benefits payable to a Beneficiary in accordance with Article IX of the Plan after the Participant's death. C. "Committee" means the Compensation Committee of the Company's Board of Directors. D. "Company" means Sempra Energy. E. "Disability" means any disability for which a Participant is entitled to benefits under the Sempra Energy Benefit Plan, the Southern California Gas Company Disability Benefit Plan, the San Diego Gas & Electric Long Term Disability Plan, the Sempra Energy Supplemental Executive Retirement Plan, or any other long-term disability plan of an Employer, and any continuation of such disability, while a Participant is not covered by such plans, which prevents a Participant from engaging in the principal duties of his employment, as verified to the Committee's satisfaction. F. "Employer" means the Company and any of its subsidiaries (any corporation of which 50% or more of the issued and outstanding stock having ordinary voting rights is owned directly or indirectly by the Company or any other business entity or association of which 50% or more of the outstanding equity interest is so owned) which adopt this Plan, or as the context requires, a Participant's particular employer. G. "Fixed Account" means the investment option that provides a fixed rate of return tied to the Moody's Rate. H. "Incentive Compensation" means the annual incentive award earned by a Participant under the Sempra Energy Executive Incentive Plan, and any other incentive compensation as specified by the Committee. I. "Investment Return" means the actual earnings or loss under any of the investment options, other than the fixed return option, made available to the Participant. J. "Moody's Plus Rate" means the Moody's Rate as defined below plus the greater of (1) 10% of the Moody's Rate or (2) one percentage point per annum. Moody's Rate is the Moody's Corporate Bond Yield Average - Monthly Average Corporates as published by Moody's Investors Service, Inc. (or any successor thereto). The Moody's Rate for the month of June, as used in this Plan, means the average of the daily Moody's Rates for June. K. "Participant" means an eligible employee who has elected to defer compensation pursuant to Article III. L. "Plan" means this Executive Deferred Compensation Plan. M. "Plan Year" means a payroll calendar year except that the first Plan Year shall be from July 1, 1998 through December 31, 1998. N. "Salary" means base salary. O. "Surviving Spouse" means a Participant's spouse married to the Participant on the Participant's date of death and still living on the date benefits are payable to a Surviving Spouse under Paragraph B of Article IX of the Plan. P. The masculine pronoun whenever used shall include the feminine pronoun, and the singular shall include the plural, as the context requires. III. Participation A. Eligibility to Participate Executive Officers of the Company as designated shall be eligible to participate in this Plan. The Committee may designate additional officers and key employees of the Employer who shall participate in this Plan and the effective date of such participation, subject to agreement by the Board of Directors of the executive's Employer (if not the Company) that such executive participate and that such Employer pay the costs of this Plan for the executive and his Surviving Spouse. B. Election to Participate Each eligible employee shall become a Participant in the Plan by electing to defer Salary, dividend equivalents, Incentive Compensation or all in accordance with Article IV of this Plan. Each eligible employee shall remain a Participant in the Plan, whether or not eligible to continue deferring Salary and Incentive Compensation, until all amounts credited to his Account have been distributed or until his death, if earlier. IV. Deferral A. Amount of Deferral An eligible employee may elect to defer 100% or any smaller percentage of his Salary payable during a Plan Year, subject to a $10,000 minimum amount. An eligible employee may elect to defer 100% or any smaller percentage of his Incentive Compensation and dividend equivalents earned during a Plan Year, whether or not he elects to defer Salary payable during the Plan Year, as permitted by the Company. The amount of Salary and Incentive Compensation deferred shall be withheld on the date or dates they otherwise would be payable to the Participant. B. Election to Defer An election to defer shall be made before the beginning of the Plan Year during which Salary is to be paid and Incentive Compensation is to be earned. Election shall be in writing, shall be modified only by adjustments permitted under the Plan, shall be made at the time and in the form prescribed by the Company, and shall be effective only upon delivery to the Company. The election shall specify the amount deferred, the deferral period, the payment method and any other matter required to be specified by the Company. C. Adjustments and Special Deferred Elections A mid-year election to make deferrals of Salary and or Bonus under the plan shall be permitted within 30 days of the commencement of employment or of any other event resulting in new eligibility. A Participant may modify his/her deferral election in the event that there is a change in a Participant's marital status or number of Dependents or there is a termination or commencement of employment of the Participant's spouse. A Participant shall be entitled to change his deferral election in a manner that is consistent with such change in marital, dependent, or employment status, by providing written notice thereof to the Company, in a form acceptable to the Company. Any such change shall be effective on the first day of the calendar month next coincident to the month in which written notice is received by the Company. V. Accounts A. Participants' Accounts For deferrals permitted by the Company and elected by a Participant a separate Account or Accounts shall be established as specified by the Company for each Plan Year. Each Account shall be treated separately for purposes of payment of benefits under the Plan. Salary, Incentive Compensation and dividend equivalents shall be credited to each Account as of the date they otherwise would have been paid to the Participant. The deferral shall be invested in the Fixed Account or as permitted by the Company, to purchase Company stock, or other equity securities. All such purchases must be made through an investment tracking device, a Rabbi Trust, or other similar instrument that causes the deferred amount not to become taxable to the Participant. All such purchases must be made in accordance with applicable Company procedures as they may be amended from time to time. The Company may permit funds in one investment option to be transferred to other investment options. B. Interest Credited on Deferrals Invested in the Fixed Account Interest shall be credited to each Account invested in the Fixed Account during each Plan Year at a rate equal to the Moody's Plus Rate for the month of June immediately prior to the Plan Year in which such interest rate is to be credited. The interest rate credited to Participants' Accounts may fluctuate from Plan Year to Plan Year. However, when distribution is to begin as to a Participant's Account, and the Participant has elected installment payments, the rate shall be fixed on the date installment payments are to begin. The fixed rate shall be the average of the Moody's Plus Rates for the June of the five prior calendar years, and that rate thereafter shall be credited to the Participant's Account from which the installment payments are to be made. Interest on each Account balance shall be credited monthly at one-twelfth the appropriate rate, compounded monthly. C. Investment Return Credited on Deferral in Other Investment Option The investment return credited to each Account during each Plan Year shall be the actual return earned or lost in the investment option. VI. Length of Deferral A. Basic Deferral Period At the time of electing deferral, a Participant shall select the period of deferral from the deferral periods specified by the Company on its prescribed election form. The period of deferral shall end, and distribution from the Participant's Account shall begin at the earliest of the Participant's death, retirement, or separation of service for any other reason unless the Company offers and the Participant selects some other deferral period. B. In-Service Distributions 1. Fixed Term Election A Participant may elect to receive an in-service distribution on such date and upon such other terms as the Company specifies at the time of the Participant's deferral election provided that no fixed term election shall be for a deferral period of less than five years. Each in-service distribution shall equal the amount in the account for the Plan Year for which the in- service distribution is elected. Amounts remaining in the Participant's Account thereafter shall continue to accrue interest or Investment Return as the case may be. 2. Unplanned Early Distribution Notwithstanding any other provisions of the Plan, by a written request filed with the Committee, a Participant, may elect to receive an immediate lump sum payment equal to the amount or a percentage of the amount deferred, or the actual amount in the Account, reduced by a penalty, which shall be forfeited to the Plan, equal to ten percent (10%) of the deferrals withdrawn in lieu of payments in accordance with the form previously elected by the Participant. The Amount remaining in the Participant's Account shall continue to earn credited interest, or Investment Return. A participant electing such an early in service distribution shall be ineligible to make deferrals for the two succeeding Plan Years. C. Hardship Withdrawal If a Participant suffers an extreme financial hardship, the Committee, in its sole and absolute discretion and upon the Participant's written application, will determine whether to permit withdrawal from the Participant's Account or Accounts. Any withdrawal that is permitted shall not exceed the amount of Salary, Incentive Compensation and dividend equivalents deferred by the Participant exclusive of credited interest or the actual amount in the Account, if less. Requests for withdrawals are expected to be unusual, and the Committee will make all determinations regarding extreme financial hardship in a uniform, nondiscriminatory manner. The term "extreme financial hardship" shall mean a severe financial hardship to the Participant resulting from a sudden and unexpected illness or accident of the Participant or of a dependent (as defined in Section 152(A) of the Internal Revenue Code) of the Participant, loss of the Participant's property due to casualty, or other similar extraordinary and unforeseeable circumstances arising as a result of events beyond the control of the Participant. The circumstances that will constitute an extreme financial hardship will depend upon the facts of each case, but, in any case, payment may not be made to the extent that such hardship is or may be relieved (1) through reimbursement or compensation by insurance or otherwise, (2) by liquidation of the Participant's assets, to the extent the liquidation of such assets would not itself cause severe financial hardship, or (3) by cessation of deferrals under the Plan. Examples of what are not considered to be extreme financial hardships include the need to send a Participant's child to college or the desire to purchase a home. VII. Method of Distribution General Distribution Election Definitions Any amount a Participant elects to receive as an in service distribution shall be paid to the Participant in a single lump sum, or in such other optional form of payment as the Company may offer and the Participant may elect at the time of his deferral election. Distribution of all other amounts credited to each Account of a Participant shall be made, as specified by the Participant at the time of electing deferral of the Salary, Incentive Compensation and dividend equivalents credited to the Account. The distribution election may be modified if, and only if, a written change of distribution election form is received by the Company no less than 12 months prior to the Participant's retirement or termination. As elected by the Participant, distribution shall be in fifteen, ten or five approximately equal annual installments or in lump sum, or in such other payment form as offered by the Company and elected by the Participant at the time of electing deferral, except as otherwise provided in Article VIII and Article IX. In the case of installment payments, all Participant account balances will be transferred to the Fixed Account at the value on the date of the first distribution. Interest at the fixed rate specified in Paragraph B of Article V shall be credited on all amounts remaining in the Participant's Account from which the installment payments are to be made. Notwithstanding anything in this Plan to the contrary, any payment made to a Participant or to his Beneficiary shall be paid according to the Participant's election after the distribution event that entitles the Participant or Beneficiary to such payment. VIII. Termination of Employment A. Accelerated Payment of Benefits If a Participant's employment with his Employer is terminated for any reason whatsoever all of the Participant's Accounts shall be paid to him in lump sum as soon as practicable thereafter, unless at least one year prior to termination, the Participant made a supplemental election of a termination distribution in either 5, 10, or 15 approximately equal annual installments as provided in Article VII, Paragraph B. A Participant who has transferred to work for the Company or any of its subsidiaries, shall not be considered to have terminated employment with his Employer for purposes of this Article. However, any salary received from a subsidiary of the Company which is not an Employer under the Plan, shall not be deferred, despite any previous deferral election. Incentive Compensation paid by the prior Employer that the Participant elected to defer prior to the transfer will be deferred. B. Earnings The interest rate which shall apply to the Participant's Fixed Accounts shall be the Moody's Plus Rate specified in Paragraph B of Article V. The earnings credited to the funds in other investment options shall be done in accordance with Section V(C). C. Disability A Participant who is unable to work due to Disability shall not be considered to have terminated employment for purposes of this Plan. Any deferral election made by the Participant shall remain in effect to the extent that the Participant thereafter receives Salary or Incentive Compensation. Disability income received on account of Disability shall not be treated as Salary unless the Committee determines otherwise, taking into consideration the best interests of the Company. IX. Benefits on Death Distribution of benefits from each Account of a Participant shall begin as soon as practicable following the Participant's death in accordance with Paragraph A or B below, depending on whether the Participant dies before or after receiving benefits. Each Account of a Participant shall be treated separately. A. Before Payments Have Begun If a Participant dies before payment from an Account has begun, other than any in service distributions made under Paragraph B(2) of Article VI, the Participant's Beneficiary will receive payment of the Participant's Account as soon as practicable after the Participant's death, as if the Participant had started to receive payment from the Account one day prior to his death. Payment to the Beneficiary shall be made in the same payment method as elected by the Participant, whether over fifteen, ten or five years, or in lump sum, or as otherwise permitted by the Company and elected by the Participant at the time of his deferral election or by subsequent election as permitted by the Plan. B. After Payments Have Begun If a Participant dies after beginning to receive payment from an Account, other than any in service distributions made under Paragraph B(2) of Article VI, the Participant's Beneficiary shall receive the remaining payments to be made from the Account if any. C. Designation of Beneficiary A Participant shall, as a condition of the right to make deferrals, designate a Beneficiary to receive the distributions described in Paragraph A or B above, whichever is applicable, following his death. Beneficiary designations shall be on the form prescribed by the Company for this purpose and shall only be effective upon delivery to the Company before the Participant's death. If a Participant designates a Beneficiary other than his spouse, his spouse's written consent to such designation must be obtained on the prescribed Beneficiary designation form. A Participant may change his Beneficiary from time to time by delivering a new designation form to the Company. If there is no designated beneficiary living at the time of a Participant's death, the estate of the deceased Participant shall be the Beneficiary. After a Participant's death, a designated Beneficiary who is to receive installment payments (not the Participant's estate) may designate a secondary beneficiary to receive any amounts due under this Plan to the Beneficiary in the event of the death of the Participant's designated Beneficiary prior to full payment to the Beneficiary. If there is no designated secondary beneficiary living at the time of death of the Participant's designated Beneficiary and installment payments remain to be paid to the Participant's Beneficiary, the estate of the Participant's designated Beneficiary shall be the beneficiary of any distributions due to the Participant's designated Beneficiary under the Plan. D. Cash Out of Small Amounts Following a Participant's death, the Company shall distribute all amounts remaining in the Participant's Account if less than $10,000, but such cash- out shall not affect the timing or the amount of benefits payable under Paragraph B above. E. Modification of Payment Method Notwithstanding any other provisions of the Plan, by a written request filed with the Committee, a retired Participant, or Beneficiary of a deceased Participant receiving benefits from the decedents Deferral Account(s), may elect to receive an immediate lump sum payment of the balance of his Deferral Account(s), reduced by a penalty, which shall be forfeited to the Plan, equal to ten percent (10%) of the balance of such Account(s), in lieu of payments in accordance with the form previously elected by the Participant. X. Administration This Plan shall be administered by the Committee. Subject to the express provisions of this Plan, the Committee shall have full and final authority to interpret the Plan, to prescribe, amend and rescind rules, regulations and guidelines relating to the Plan, and to make any other determinations it believes necessary or advisable for the administration of the Plan. All decisions and determinations by the Committee shall be final and binding upon all parties. No member of the Committee who is also a Participant in this Plan shall decide or vote on any matter that would affect such Participant in a manner materially different from other Participants. The Company's Senior Human Resources Officer shall have discretionary authority with respect to administrative matters relating to this Plan, except when exercise of such authority would materially affect the cost of the Plan to the Employer, materially increase benefits to Participants, or affect such Senior Officer in a manner materially different from other Participants. XI. Amendment or Termination of the Plan The Committee may, in its sole discretion, suspend, amend or terminate this Plan at any time, in whole or in part. However, such action shall be prospective only and shall not adversely affect the rights of any Participant, Beneficiary or Surviving Spouse to any amounts previously credited to a Participant's Account or Accounts under the Plan. The Committee may increase or decrease the interest rate credited to Participants' Fixed Accounts, including Salary, Incentive Compensation and dividend equivalents previously deferred, but the rate shall not be decreased for periods prior to such action. Any termination of the Plan shall not result in automatic payment of Accounts, and Participants' Accounts shall be paid under the terms of the Plan as in effect prior to termination. However, in the event a final determination is made by a court of competent jurisdiction, or by the relevant tax authorities, and no appeal is taken therefrom, that amounts deferred under this Plan are taxable income to a Participant prior to the time they otherwise would be distributed under the Plan, the Committee may terminate the Plan as to such Participant and immediately pay to him, or on his death to his Beneficiary, all amounts that are so taxable. XII. Miscellaneous A. No Employment Right Nothing contained herein shall confer upon any Participant the right to be retained in employment by his Employer, nor will it interfere with the right of his Employer to discharge or otherwise deal with the Participant without regard to the existence of this Plan. B. Insurance As a condition of participation in this Plan, each Participant shall, if requested by the Company, undergo such examination and provide such information as may be required by the Company with respect to any insurance contracts on the Participant's life, and shall authorize the Company to purchase life insurance on his life, payable to the Company. If an insurance policy is invalidated because a Participant commits suicide during the two-year period beginning on the first day of the first Plan Year of such Participant's participation in the Plan, or if the Participant makes any material misstatement of information or nondisclosure of medical history, then no benefits will be payable hereunder to such Participant, his Beneficiary or his Surviving Spouse, other than payment of the amount of deferrals of Salary, Incentive Compensation and dividend equivalents then credited to the Participant's Accounts, without any interest, including interest theretofore credited under this Plan. C. Source of Payment This Plan is unfunded, and distributions shall be made solely on a current disbursement basis. Each Participant, his Beneficiary and his Surviving Spouse shall be no more than unsecured general creditors of the Company, and nothing contained in this Plan shall be deemed to create a trust of any kind, for the benefit of any Participant, Beneficiary or Surviving Spouse, or create any fiduciary relationship between the Company and any Participant, Beneficiary, or Surviving Spouse with respect to any assets of the Company, including, but not limited to, any insurance policies which the Company may purchase on the life of the Participant. The Company, however, retains the right to establish reserves for the obligations hereunder including, but not limited to corporate owned life insurance, and assets held in a "Rabbi Trust." Provided that in the event that the Chief Executive Officer determines that a change in control as defined in the Sempra Energy Long Term Incentive Plan, is imminent then assets shall be placed in the Deferred Compensation Trust which when combined with any assets then in the trust shall equal the full accrued liability under this Plan as determined by Towers and Perrin, or a successor actuarial firm. D. Withholding Each Participant, Beneficiary and Surviving Spouse to whom distribution is made shall make appropriate arrangements for the satisfaction of any federal, state, or local income tax withholding requirements, any social security or other employment tax requirements applicable to the payment of benefits under this Plan, and any payments the Participant agreed to make to the Company or to his Employer. If no other arrangements are made, the Company may provide, at its discretion, for such withholding and tax payments as may be required. E. Nonassignment To the maximum extent permitted by law, no benefit under this Plan shall be assignable or subject in any manner to alienation, sale, transfer, claims of creditors, pledge, attachment or encumbrances of any kind. F. Governing Law This Plan is established under and will be construed according to the laws of the State of California to the extent that such laws are not preempted by the Employee Retirement Income Security Act of 1974, as amended. G. Effective Date This Plan is effective June 1, 1998.

Exhibit 10.13 SEMPRA ENERGY RETIREMENT PLAN FOR DIRECTORS Effective June 1, 1998 1. Purpose The purpose of this unfunded plan is to retain outstanding directors for Sempra Energy. 2. Eligibility Members of the Sempra Energy Board of Directors who participated in a Director Retirement Plan maintained by Pacific Enterprises, Enova corporation or San Diego Gas & Electric ("Prior Plan") shall be eligible to participate in this Plan which is a successor to the Prior Plan. Directors shall retire no later than the Annual Meeting of the company held on or after the director's 72nd birthday. 3. Benefit Amount Each eligible director is entitled to an annual retirement benefit equal to the sum of (a) the then-current year's annual base retainer (exclusive of any amount paid for committee service); and (b) the then- current fee for attending a regularly scheduled meeting of the full Board in California, multiplied by 10, subject to upward adjustments if the retainer and/or meeting fee increases subsequent to retirement. In the event that an increase occurs, the directors' retirement benefit will be adjusted effective with the next scheduled payment. Retirement benefits payable to directors who retired under a Prior Plan, are governed by that plan as in effect at the time of retirement. The amount of the annual retirement benefit will not be affected by a director's deferral of compensation under the Deferred Compensation Plan for Directors. 4. Benefit Duration Benefit payments will start on the first day of the calendar quarter on or after the date an eligible director leaves the Board, provided the director is at least age 65. An eligible director who leaves the Board prior to age 65 will start receiving benefit payments on the first day of the calendar quarter in which the director turns 65. Benefits will be paid on the first day of each quarter thereafter, and will be paid for a period equal to the length of the director's service as an outside director under the Prior Plan plus the director's service as an outside director under this plan to a maximum of the greater of five years or ten years less the years of Participation under the Prior Plan or until death, whichever occurs first. Each quarterly payment will be one-fourth the annual retirement benefit. There are no death benefits payable under this plan except as provided in paragraph 5. 5. Survivor Benefits If a married eligible director dies after the start of benefit payments, his/her surviving spouse shall receive the remaining payments, if any, to which the eligible director would have been entitled but for his/her death. Such benefits will cease upon the surviving spouse's death. If an eligible married director dies prior to the start of benefit payments, his/her surviving spouse will start receiving benefits calculated pursuant to paragraph 3, on the first day of the calendar quarter next following the eligible director's death. Benefits will be paid for a period equal to the length of the eligible director's service as an outside director or until the surviving spouse's death, whichever occurs first. 6. Administration The Company's Compensation Committee shall have full and final authority to interpret this plan and to make determinations that it believes advisable for the administration of the plan. All decisions and determinations by the Compensation Committee shall be final and binding upon all parties. 7. Grandfather Benefit In the event that the retirement benefit calculated under the terms of a Prior Plan is greater than the benefit amount under paragraph 3 herein, the eligible director shall receive a benefit equal to such Prior Plan retirement benefit subject to the maximum provided in 4 above.