-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, JEaTYMVzb8gtZeeiKH8w4KMWpZ1h6uCewOnGHQCD+VqkDK9lm5BAkY3pTndBd++s 13UvtAsBl2RTLtnRvSdJhg== 0000086521-00-000007.txt : 20000411 0000086521-00-000007.hdr.sgml : 20000411 ACCESSION NUMBER: 0000086521-00-000007 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19991231 FILED AS OF DATE: 20000329 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SEMPRA ENERGY CENTRAL INDEX KEY: 0001032208 STANDARD INDUSTRIAL CLASSIFICATION: GAS & OTHER SERVICES COMBINED [4932] IRS NUMBER: 330732627 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: SEC FILE NUMBER: 001-14201 FILM NUMBER: 582622 BUSINESS ADDRESS: STREET 1: 101 ASH STREET STREET 2: P O BOX 129400 CITY: SAN DIEGO STATE: CA ZIP: 92101 BUSINESS PHONE: 6196962000 MAIL ADDRESS: STREET 1: 101 ASH STREET STREET 2: P O BOX 129400 CITY: SAN DIEGO STATE: CA ZIP: 92101 FORMER COMPANY: FORMER CONFORMED NAME: MINERAL ENERGY CO DATE OF NAME CHANGE: 19970205 10-K 1 FORM 10-K 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, 1999 -------------------- 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 33. Glossary on page 41. Aggregate market value of the voting stock held by non-affiliates of the registrant as of March 23, 2000 was $3.4 billion. Registrant's common stock outstanding as of March 23, 2000 was 204,220,661 shares. DOCUMENTS INCORPORATED BY REFERENCE: Portions of the 1999 Annual Report to Shareholders are incorporated by reference into Parts I, II, and IV. Portions of the Proxy Statement prepared for the May 2000 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. . . . . . . . . . . . . . . . . . .22 Item 4. Submission of Matters to a Vote of Security Holders. .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 . . . . . . . .24 Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . .24 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 . .25 Item 11. Executive Compensation . . . . . . . . . . . . . . . .26 Item 12. Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . . .26 Item 13. Certain Relationships and Related Transactions . . . .26 PART IV Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . . . . . . . . . .27 Independent Auditors' Consent and Report on Schedule. . . . . .29 Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . .32 Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . .33 Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . .41 This report contains statements that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The words "estimates," "believes," "expects," "anticipates," "plans" "intends," "may" and "should" or similar expressions, or discussions of strategy or of plans are intended to identify forward-looking statements that involve risks, uncertainties and assumptions. Future results may differ materially from those expressed in these forward-looking statements. These statements are necessarily based upon various assumptions involving judgments with respect to the future and other risks, 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; exchange rates; energy markets, including the timing and extent of changes in commodity prices; weather conditions; business and regulatory or legal decisions; the pace of deregulation of retail natural gas and electricity delivery; 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. Readers are cautioned not to rely unduly on any forward-looking statements and are urged to review and consider carefully 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 1999 Annual Report to Shareholders, which is incorporated by reference. GOVERNMENT REGULATION The most significant government regulation affecting Sempra Energy is that affecting its utility subsidiaries, which is discussed below. Other subsidiaries are also subject to governmental 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/or 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). California Utility 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. United States Utility Regulation The Federal Energy Regulatory Commission (FERC) regulates the interstate sale and transportation of natural gas, regulates the transmission and wholesale sales of electricity in interstate commerce, transmission access, the uniform systems of accounts, rates of depreciation and electric rates involving sales for resale. 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. International Utility Regulation The Company's consolidated and unconsolidated affiliates have locations in Argentina, Canada, Chile, Mexico, Peru and Uruguay. These operations are subject to the local, federal and other regulations of the countries in which they are located. Licenses and Permits SoCalGas and SDG&E obtain 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. In addition, SDG&E obtains a number of permits, authorizations and licenses in connection with the transmission and distribution of electricity. Other regulatory matters are described throughout this report. SOURCES OF REVENUE 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 1999 Annual Report to Shareholders, which is incorporated by reference. NATURAL GAS OPERATIONS The Company purchases, sells, distributes, stores and transports natural gas. SDG&E supplies natural gas to its customers (including transport to electric generating plants) in San Diego and southern Orange counties, comprising a 4,100-square-mile service territory. SoCalGas owns and operates a natural gas distribution, transmission and storage system that supplies natural gas to its customers (including transport to electric generating plants) throughout a 23,000-square-mile service territory from central California to the Mexican border. On a smaller scale, Sempra Energy International (SEI) operates natural gas distribution systems in Mexico through 60 percent, 95 percent and 100 percent ownership of DGN-Mexicali, DGN-Chihuahua and DGN-La Laguna, respectively. The operations of SoCalGas, SDG&E and SEI's operations in Mexico are included in the following discussion of the Company's natural gas operations. SEI also has interests in natural gas operations in South America which are not consolidated and, therefore, are not included in these discussions. Additional information on international operations is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations." 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. SoCalGas has firm pipeline capacity contracts with pipeline companies that expire at various dates through 2006. SDG&E has long-term capacity contracts with interstate pipelines which expire at various dates between 2007 and 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 other sources by the Company or its transportation customers. 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 1999 Annual Report to Shareholders, which is incorporated by reference. The following table shows the sources of natural gas deliveries from 1995 through 1999.
Year Ended December 31 ------------------------------------------------------------------- 1999 1998 1997 1996 1995 - ------------------------------------------------------------------------------------------------------------- Natural Gas Purchases: (billions of cubic feet) Spot market 390 388 330 323 296 Long-term contracts 76 104 100 108 128 ------- ------- ------- ------- ------- Total Purchases 466 492 430 431 424 Customer-owned and exchange receipts 574 521 514 422 531 Storage withdrawal (injection) - net (6) (28) (3) 42 (13) Company use and unaccounted for (16) (23) (11) (11) (5) ------- ------- ------- ------- ------- Net Deliveries 1,018 962 930 884 937 ======= ======= ======= ======= ======= Natural Gas Purchases: (millions of dollars) Commodity costs $1,084 $1,092 $1,160 $ 879 $ 666 Fixed charges* 147 174 250 276 264 ------- ------- ------- ------- ------- Total Purchases $1,231 $1,266 $1,410 $1,155 $ 930 ======= ======= ======= ======= ======= Average Commodity Cost of Purchases (Dollars per Thousand Cubic Feet) $ 2.33 $ 2.22 $ 2.69 $ 2.04 $ 1.57 ======= ======= ======= ======= ======= * 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 and SDG&E.
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 91 percent of total natural gas volumes purchased by the Company during 1999, as compared with 79 percent and 77 percent during 1998 and 1997, respectively. These supplies were generally purchased at prices significantly below those of long-term, fixed-price sources of supply. During 1999, the Company, including its Mexico operations, delivered 1,018 bcf of natural gas through its system. Approximately 56 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. Noncore customers consist primarily of utility electric generation (UEG), wholesale, large commercial, industrial and off- system (outside the Company's normal service territory) customers. Of the 5.7 million customer meters in the Company's service territory, only 1,700 serve the noncore market. 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 1999 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 1999 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 revenues from transportation throughput is less than for natural gas sales, the Company generally earns the same margin whether the Company buys the gas and sells it to the customer or transports natural gas already owned by the customer. 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, 1999, the Company was storing approximately 22 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. Excluding customer meters in Mexico of approximately 20,000, the Company added approximately 101,000 and 58,000 new customer meters in 1999 and 1998, respectively, representing growth rates of 1.5 percent and 1.0 percent, respectively. The Company expects its growth rate for 2000 to be at the 1999 level. During 1999, 99 percent of residential energy customers in SoCalGas' service area used natural gas for water heating, 96 percent for space heating, 76 percent for cooking and 55 percent for clothes drying. In SDG&E's service area, 91 percent of residential energy customers used natural gas for water heating, 73 percent for space heating, 52 percent for cooking and 35 percent for clothes drying. Demand for natural gas by noncore customers is very sensitive to the price of competing fuels. Although the number of noncore customers in 1999 was only 1,700, they accounted for approximately 13 percent of the authorized natural gas revenues and 57 percent of total natural gas volumes. External factors such as weather, electric deregulation, the use of hydro-electric power, competing pipeline bypass and general economic conditions can result in significant shifts in this market. The demand for natural gas by 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 1999 for UEG customer use increased primarily due to higher electric energy usage in the summer, as a result of warmer weather. UEG customer demand decreased in 1998 as a result of decreased demand for electricity. Effective March 31, 1998, electric industry restructuring gave California consumers the option of selecting their electric energy provider from a variety of local and out-of-state producers. As a result, natural gas demand for electric generation within southern California competes with electric power generated throughout the western United States. Although 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 Notes 13 and 14 of the notes to Consolidated Financial Statements of the 1999 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. As mentioned briefly above, 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 1999 Annual Report to Shareholders, which is incorporated by reference. Electric Resources In connection with California's 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 also are obligated to purchase from the PX the power that they sell. An Independent System Operator (ISO) schedules power transactions and access to the transmission system. In 1999, SDG&E completed divestiture of its owned generation other than nuclear. SDG&E continues to have purchased-power contracts, which it bids into the PX. Based on generating plants in service and purchased- power contracts currently in place, at February 29, 2000 the megawatts (mw) of electric power available to SDG&E to bid into the PX are as follows: Source Mw -------------------------------------------------- Nuclear generating plants 430* Long-term contracts with other utilities 175 Contracts with others 493 ----- Total 1,098 ===== * Net of plants' internal usage Natural 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. During the quarter ended June 30, 1999, these sales were completed for total net proceeds of $466 million. The South Bay Power Plant sale to the San Diego Unified Port District for $110 million was completed on April 23, 1999. Duke South Bay, a subsidiary of Duke Energy Power Services, will manage the plant for the Port District. The sale of Encina Power Plant and 17 combustion-turbine generators to Dynegy Inc. and NRG Energy Inc. for $356 million was completed on May 21, 1999. SDG&E will operate and maintain both facilities for the new owners for the next two years. San Onofre Nuclear Generating Station (SONGS): SDG&E owns 20 percent of the three nuclear units at SONGS (located south of San Clemente, California). The cities of Riverside and Anaheim own a total of 5 percent of Units 2 and 3. Southern California Edison (Edison) owns the remaining interests and operates the units. 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. 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. In June 1999, the CPUC granted authority to begin decommissioning Unit 1. That work is now in progress. 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 1999 SDG&E spent $10 million on capital modifications and additions and expects to spend $6 million in 2000. SDG&E deposits funds in an external trust to provide for the future dismantling and decontamination of the units. Additional Information: Additional information concerning the SONGS units, nuclear decommissioning and industry restructuring (including SDG&E's divestiture of its electric generation assets) is provided below and in "Environmental Matters" and "Electric Properties" herein, and 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 1999 Annual Report to Shareholders, which is incorporated by reference. Purchased Power: The following table lists contracts with the various suppliers: Expiration Megawatt Supplier Date Commitment Source - ------------------------------------------------------------------- Long-Term Contracts with Other Utilities: Portland General Electric (PGE) December 2013 75 Coal Public Service Company of New Mexico (PNM) April 2001 100 System supply ----- Total 175 ===== Other Contracts: PacifiCorp December 2001 100 System Supply Avista Supply December 2001 150 System Supply Applied Energy December 2019 102 Cogeneration Yuma Cogeneration June 2024 50 Cogeneration Goal Line Limited Partnership December 2025 50 Cogeneration Other (89) Various 41 Cogeneration ------ Total 493 ====== 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 and Avista are for firm energy only and are based on the amount of energy received. The prices under these contracts are at the 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 below, and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note 13 of the notes to Consolidated Financial Statements of the 1999 Annual Report to Shareholders, which is incorporated by reference. Power Pools 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 200 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. Transmission Arrangements Pacific Intertie: The Pacific Intertie, consisting of AC and DC transmission lines, connects the Northwest with SDG&E, Pacific Gas & Electric (PG&E), Edison and others under an agreement that expires in July 2007. SDG&E's share of the intertie was 266 mw. 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. 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. Due to electric-industry restructuring (see "Transmission Access" below), the operating rights of SDG&E on these lines have been transferred to the ISO. 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 provided below and in "Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 1999 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 - ------------------------------------------------------------------- 1999 1998 1997 1999 1998 1997 ----- ----- ----- ---- ---- ---- Natural gas 6.5% 17.3% 19.8% 3.0 3.0 3.3 Nuclear fuel 12.6 11.5 11.8 0.5 0.6 0.6 Fuel oil 0.1 2.4 ----- ----- ----- Total generation 19.1 28.8 31.7 Purchased power and ISO/PX 80.9 71.2 68.3 3.7 3.5 2.8 ----- ----- ----- Total 100.0% 100.0% 100.0% ====== ====== ====== As described previously, SDG&E sold its South Bay and Encina power plants and 17 combustion turbines during the quarter ended June 30, 1999. Since the primary fuel source of these plants is natural gas, the percentage of Kwhr for natural gas in the above table decreased compared to 1998. 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 under contract through 2003, including mining and milling of uranium concentrate, conversion of uranium concentrate to uranium hexafluoride, enrichment services and enriched uranium hexafluoride, and fabrication of fuel assemblies. Spent fuel is being stored at SONGS, where storage capacity will be adequate at least through 2005. 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 provided in Note 13 of the notes to consolidated financial statements of the 1999 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. SEI has interests in natural gas and/or electric transmission and distribution projects in Argentina, Canada, Chile, Mexico, Peru and Uruguay and is pursuing other projects in Latin America. In June 1999, SEI and Public Service Enterprise Group (PSEG) announced the completion of the joint purchase of 90 percent of Chilquinta Energia S.A. (Energia). In January 2000, SEI and PSEG purchased an additional 9.75 percent of Energia, increasing their total holdings to 99.98 percent. In September 1999, SEI and PSEG completed their acquisition of 47.5 percent of the outstanding shares of Luz del Sur S.A., a Peruvian Electric Company. This acquisition, combined with the 37 percent already owned through Energia, increased the companies' total joint ownership to 84.5 percent of Luz del Sur S.A. In March 1998, Pacific Enterprises (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. In June, 1999, the Company contributed capital to Sodigas Pampeana S.A. and Sodigas Sur S.A. to retire $32 million of debt outstanding. These natural gas distribution companies serve 1.2 million customers in central and southern Argentina, respectively, and have a combined throughput of 650 million cubic feet per day. SEI owns 60 percent of Distribuidora de Gas Natural de Mexicali, S. de R.L. de C.V. (DGN-Mexicali), a Mexican company that holds 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. It will invest up to $25 million to provide service to 25,000 customers during the first five years of operation, of which one-third has been spent as of December 31, 1999. SEI owns 95 percent of 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, it acquired ownership of a 16-mile transmission pipeline serving 20 industrial customers. It will invest nearly $50 million to provide service to 50,000 customers in the first five years of operation, of which one-half has been spent as of December 31, 1999. In May 1999 SEI was awarded a 30-year license to build and operate a natural gas distribution system in the La Laguna-Durango zone in north-central Mexico. SEI will invest over $40 million in the project during the first five years of operation. In August 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 provides 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. Construction of the pipeline is anticipated to be completed by mid-2000 at a cost of $35 million. The pipeline will also serve as a link for a natural gas distribution system in Tijuana, Baja California, between San Diego and Rosarito. 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 in discussions with the Uruguayan government in regard to the terms of the concession agreement. Net income for international operations in 1999 was $10 million compared to net losses of $4 million and $9 million for 1998 and 1997, respectively. Additional information on international operations is provided 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 1999 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 acquired on December 31, 1997. 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. During 1999, SET commenced its European operations, opening offices in Dusseldorf, Oslo and London. 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, 1999, SET had operating revenues of $450 million and net income of $19 million. Additional information on SET is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Notes 3, 10 and 15 of the notes to Consolidated Financial Statements of the 1999 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. It is the responsibility of the CPUC to determine that utilities operate within the best interests of their customers. The regulatory structure is complex and has a substantial impact on the profitability of the Company. Both the electric and natural gas industries are currently undergoing transitions to competition. 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 provided 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 1999 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. Additional information on natural gas industry restructuring is provided 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 1999 Annual Report to Shareholders, which is incorporated by reference. Balancing Accounts In general, earnings fluctuations from changes in the costs of natural gas and consumption levels for the majority of natural gas are eliminated by balancing accounts authorized by the CPUC. 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 certain costs and consumption levels now can affect earnings from electric operations. Additional information on balancing accounts is provided 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 1999 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. Additional information on PBR is provided 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 1999 Annual Report to Shareholders, which is incorporated by reference. Biennial Cost Allocation Proceeding (BCAP) Rates to recover the changes in the cost of natural gas transportation services are determined in the BCAP. The BCAP adjusts rates to reflect variances in customer demand from estimates previously used in establishing customer natural gas transportation rates. The mechanism substantially eliminates the effect on income of variances in market demand and natural gas transportation costs and, for SoCalGas, is subject to the limitations of the Gas Cost Incentive Mechanism (GCIM) provided below. The BCAP will continue under PBR. Additional information on the BCAP is provided 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 1999 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 provided 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 1999 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 IOUs conduct business with their affiliates. Information on affiliate transactions is provided 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 1999 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 indices exceed established tolerances. Additional information on the utilities' cost of capital is provided 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 1999 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 1999 Annual Report to Shareholders, which is incorporated by reference. The following additional information should be read in conjunction with those discussions. Hazardous Substances In 1994, the CPUC approved the Hazardous Waste Collaborative balancing account, a mechanism that allows SoCalGas, SDG&E and other utilities to recover in rates the 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. 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, discussed in Note 14 of the notes to Consolidated Financial Statements of the 1999 Annual Report to Shareholders, which is incorporated by reference. During the early 1900s, SDG&E, SoCalGas and their predecessors manufactured gas from coal or oil. The manufacturing sites often have become contaminated with the hazardous residual by-products of the process. SDG&E has identified three former manufactured-gas plant sites. One site has received a site-closure letter and an environmental assessment has been conducted at the other two sites. At December 31, 1999 estimated remaining remediation liability on these two sites is $3 million. In addition, SoCalGas has identified 42 former manufactured-gas plant sites at which it (together with other users as to 21 of these sites) may have cleanup obligations. As of December 31, 1999, 13 of these sites have been remediated, of which 10 have received certification from the California Environmental Protection Agency. Preliminary investigations, at a minimum, have been completed on 39 of the sites. At December 31, 1999, SoCalGas' estimated remaining investigation and remediation liability for all of these sites is $64 million. Station B, located in downtown San Diego, was operated as a steam and electric generating facility between 1911 and June 1993. Activities to dismantle and decommission the facility required the removal of asbestos and lead-based paint, and the removal or cleanup of other substances. These activities were completed in 1999 at a cost of $6 million. The sale of Station B was completed in December 1999. SDG&E sold the South Bay and Encina power plants and 17 combustion turbines in 1999. SDG&E conducted a thorough environmental assessment of the power plants and combustion turbine sites. Pursuant to the sale agreements, SDG&E and the buyers have apportioned responsibility for remediation obligations for contamination existing on these sites. Estimated costs to perform the necessary remediation at all sites are approximately $10 million. Together with other appropriate costs, these costs were offset against the sales price for the facilities and the remaining net proceeds were offset against SDG&E's other transition costs. The Company and other subsidiaries have been named as potentially responsible parties (PRPs) in relation to two landfills and four industrial waste disposal sites as described below. Remedial actions and negotiations with other PRPs and the United States Environmental Protection Agency (EPA) have been in progress since 1986 and 1993 for the two landfill sites. The Company's share of costs to remediate these sites is estimated to be approximately $3.7 million, of which $1.2 million was incurred during 1999. In the early 1990s, the Company was notified of two industrial waste treatment facilities. A feasibility study and remedial investigation have been submitted and accepted by the EPA for one of these sites. Total estimated remediation cost for both facilities is $420,000. The Company and 10 other entities have been named PRPs by the Department of Toxic Substance Control (DTSC) as liable for any required corrective action regarding contamination at an industrial waste disposal site in Pico Rivera, California. DTSC has taken this action because SDG&E and others sold used transformers to the site's owner. SDG&E and the other PRPs have entered into a cost- sharing agreement to provide funding for the implementation of a consent order between DTSC and the site owner for the development of a cleanup plan. SDG&E's interim share under the agreement is 10.1%, subject to adjustment based on the ultimate responsibility allocations. The estimate for the development of the cleanup plan and the actual cleanup is $3 million to $9 million. In December 1999, SoCalGas was notified that it is a PRP at the Gibson Oil waste treatment facility in Bakersfield, California. SoCalGas is working with other PRPs in order to remove from the site certain liquid wastes that threaten to be released. It is too early to determine the existence or extent of any prior releases or the Company's potential total liability. At December 31, 1999, the Company's estimated remaining investigation and remediation liability related to hazardous waste sites, including the manufactured gas sites, was $70 million, of which 90 percent is authorized to be recovered through the Hazardous Waste Collaborative mechanism. This estimated cost excludes remediation cost associated with the sale of the electric- generation plants and the 17 combustion turbines. The Company believes that any costs not ultimately recovered through rates, insurance or other means, will not have a material adverse effect on the Company's consolidated results of operations or 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. Electric and Magnetic Fields (EMFs) Although scientists continue to research the possibility that exposure to EMFs causes adverse health effects, science has not demonstrated a cause-and-effect relationship between adverse health effects and exposure to the type of EMFs emitted by 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 California's air quality standards are more restrictive than federal standards. However, as a result of the sale of the Company's fossil-fuel power plants and combustion turbines, the Company's primary air-quality issue, compliance with these standards is less significant. 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. 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 fish hatchery programs and pay for monitoring and oversight of the mitigation projects. SDG&E's share of the cost is estimated to be $24 million. The pricing structure contained in the CPUC's decision regarding accelerated recovery of SONGS Units 2 and 3 is expected to accommodate these added mitigation costs. OTHER MATTERS Year 2000 There were only a few, very minor Year 2000 interruptions to the Company's automated systems and applications, suppliers and customers. The Company incurred expenses of $48 million (including $7.6 million in 1999) for its Year 2000 readiness effort and expects to incur no additional costs. Research, Development and Demonstration (RD&D) The SoCalGas RD&D portfolio is focused in five major areas: Operations, Utilization Systems, Power Generation, Public Interest and Transportation. Each of these activities provides benefits to customers and society by providing more cost-effective, efficient natural gas equipment with lower emissions, increased safety and reduced environmental mitigation and other utility operating costs. The CPUC has authorized SoCalGas to recover its operating cost associated with RD&D. SoCalGas' annual RD&D costs have averaged $9.1 million over the past three years. As a result of electric-industry restructuring, SDG&E has significantly reduced its electric RD&D program. For 1999, the CPUC authorized SDG&E to fund $1.2 million and $4 million in its natural gas and electric RD&D programs, respectively, which includes $3.9 million to the CEC's electric public purpose RD&D program. SDG&E's annual RD&D costs have averaged $4.7 million over the past three years. Employees of Registrant As of December 31, 1999 the Company had 11,248 employees, compared to 11,148 at December 31, 1998. Wages SoCalGas and SDG&E employ over 9,000 persons. At SoCalGas, field, technical and most clerical employees 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. Negotiations for a new agreement are ongoing. 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 the transmission and distribution contract runs through August 31, 2001. 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, 1999, the Company owned approximately 3,021 miles of transmission and storage pipeline, 51,566 miles of distribution pipeline and 50,002 miles of service piping. It also owned 12 transmission compressor stations and 6 underground storage reservoirs (with a combined working capacity of approximately 117.8 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. 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 equipment necessary in the conduct of business. ITEM 3. LEGAL PROCEEDINGS Neither Sempra Energy nor its subsidiaries are party to, nor is their property the subject of, any material pending legal proceedings other than routine litigation incidental to their businesses. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS None 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 March 23, 2000 there were approximately 80,000 holders of record of the Company's common stock. The quarterly common stock information, including high and low sales prices and dividend declarations, required by Item 5 is included in the schedule of Quarterly Financial Data of the 1999 Annual Report to Shareholders, which is incorporated by reference. Dividend Restrictions At December 31, 1999, $863 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 provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" of the 1999 Annual Report to Shareholders, which is incorporated by reference. ITEM 6. SELECTED FINANCIAL DATA
At December 31, or for the years then ended ------------------------------------------------ (Dollars in millions) 1999 1998 1997 1996 1995 -------- ------- ------- ------- ------- Income Statement Data: Revenues and other income $ 5,435 $ 5,015 $ 5,115 $ 4,524 $ 4,201 Operating income $ 802 $ 629 $ 927 $ 927 $ 886 Net income $ 394 $ 294 $ 432 $ 427 $ 401 Balance Sheet Data: Total assets $11,270 $10,456 $10,756 $ 9,762 $ 9,837 Long-term debt $ 2,902 $ 2,795 $ 3,175 $ 2,704 $ 2,721 Short-term debt (a) $ 337 $ 373 $ 624 $ 481 $ 485 Shareholders' equity $ 2,986 $ 2,913 $ 2,959 $ 2,930 $ 2,815 Per Common Share Data Net income Basic $ 1.66 $ 1.24 $ 1.83 $ 1.77 $ 1.67 Diluted $ 1.66 $ 1.24 $ 1.82 $ 1.77 $ 1.67 Dividends declared $ 1.56 $ 1.56 $ 1.27 $ 1.24 $ 1.22 Book value $ 12.58 $ 12.29 $ 12.56 $ 12.21 $ 11.70 (a) Includes long-term debt due within one year. This data should be read in conjunction with the Consolidated Financial Statements and the notes to Consolidated Financial Statements contained in the 1999 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 19 through 35 of the 1999 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 32 through 35 of the 1999 Annual Report to Shareholders. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required by Item 8 is incorporated by reference from pages 38 through 70 of the 1999 Annual Report to Shareholders. Item 14(a)1 includes a listing of financial statements included in the 1999 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 2000 annual meeting of shareholders. The information required on the Company's executive officers is provided below. EXECUTIVE OFFICERS OF THE REGISTRANT Name Age* Positions - --------------------------------------------------------------------- Richard D. Farman 64 Chairman and Chief Executive Officer Stephen L. Baum 58 Vice Chairman, President and Chief Operating Officer Donald E. Felsinger 52 Group President, Unregulated Business Units Warren I. Mitchell 62 Group President, Regulated Business Units John R. Light 58 Executive Vice President and General Counsel Neal E. Schmale 53 Executive Vice President and Chief Financial Officer Darcel L. Hulse 52 Senior Vice President Frederick E. John 53 Senior Vice President, External Affairs Margot A. Kyd 46 Senior Vice President, Chief Administrative and Environmental Officer G. Joyce Rowland 45 Senior Vice President, Human Resources and Chief Ethics Officer Frank H. Ault 55 Vice President and Controller * As of December 31, 1999. 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. Hulse, Light and Schmale. Prior to joining the Company in 1999, Mr. Hulse was President of Unocal Asia-Pacific Ventures. 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. 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 2000 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 2000 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. . . . . . . . . . . 37 Independent Auditors' Report . . . . . . . . . . . . . . 38 Statements of Consolidated Income for the years ended December 31, 1999, 1998 and 1997 . . . . . . . . 39 Consolidated Balance Sheets at December 31, 1999 and 1998. . . . . . . . . . . . . . . . . . . . . 40 Statements of Consolidated Cash Flows for the years ended December 31, 1999, 1998 and 1997 . . . . . 42 Statements of Consolidated Changes in Shareholders' Equity for the years ended December 31, 1999, 1998 and 1997 . . . . . . . . . . . 44 Notes to Consolidated Financial Statements . . . . . . . 45 *Incorporated by reference from the indicated pages of the 1999 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. . . . . . . . . . . . . . . . . . 29 Schedule I--Condensed Financial Information of Parent. . 30 Any other schedules for which provision is made in Regulation S-X are not required under the instructions contained therein or are inapplicable. 3. Exhibits See Exhibit Index on page 33 of this report. (b) Reports on Form 8-K The following reports on Form 8-K were filed after September 30, 1999: Current Report on Form 8-K filed January 28, 2000 and Amended Current Report on Form 8-K/A filed February 8, 2000 reported earnings for the year ended December 31, 1999 and announced a tender offer to purchase common shares and a dividend reduction. Current Report on Form 8-K filed February 18, 2000 and Current Report on Form 8-K filed February 22, 2000 announced the sale of $200,000,000 of 8.9% Cumulative Quarterly Income Preferred Securities (Series A) and the execution of an underwriting agreement for the issuance and sale of $500,000,000 aggregate principal amount 7.95% Notes due 2010. Current Report on Form 8-K filed March 9, 2000 reported the final results of the tender offer to purchase common shares. 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 Numbers 333-51309 and 333-77843 on Form S-3 and Registration Statement Number 333-56161 on Form S-8 of Sempra Energy of our report dated February 4, 2000 (February 25, 2000 as to Note 17), incorporated by reference in this Annual Report on Form 10-K of Sempra Energy for the year ended December 31, 1999. 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. /S/ DELOITTE & TOUCHE LLP San Diego, California March 28, 2000 Schedule I -- CONDENSED FINANCIAL INFORMATION OF PARENT SEMPRA ENERGY Condensed Statement of Income (Dollars in millions, except per share amounts) For the year ended December 31 1999 1998 -------- -------- Operating revenues and other income $ 9 $ -- Operating expenses, interest and income taxes 22 10 -------- -------- Loss before subsidiary earnings (13) (10) Subsidiary earnings 407 304 -------- -------- Net income $ 394 $ 294 ======== ======== Average common shares outstanding (basic) 237,245 236,423 -------- -------- Average common shares outstanding (diluted) 237,553 237,124 -------- -------- Net income per common share (basic) $ 1.66 $ 1.24 -------- -------- Net income per common share (diluted) $ 1.66 $ 1.24 ======== ======== Condensed Balance Sheet (Dollars in millions) Balance at December 31 1999 1998 -------- -------- Assets: Cash and cash equivalents $ -- $ 67 Dividends receivable -- 100 Other current assets 11 174 -------- -------- Total current assets 11 341 Investments in subsidiaries 3,828 2,820 Other assets 167 106 -------- -------- Total Assets $ 4,006 $ 3,267 ======== ======== Liabilities and Shareholders' Equity: Dividends payable $ 94 $ 93 Other current liabilities 298 221 -------- -------- Total current liabilities 392 314 Long-term debt 138 9 Loan from SDG&E 422 -- Other long-term liabilities 68 31 Common equity 2,986 2,913 -------- -------- Total Liabilities and Shareholders' Equity $ 4,006 $ 3,267 ======== ======= SEMPRA ENERGY Condensed Statement of Cash Flows (Dollars in millions) For the year ended December 31 1999 1998 -------- -------- Cash flows from operating activities $ 337 $ 71 -------- -------- Sale of common stock 3 4 Loan from SDG&E 422 -- Dividends paid (368) (94) -------- -------- Cash provided by (used in) financing activities 57 (90) -------- -------- Expenditures for property, plant and equipment (86) (44) Increase in investments and other assets (475) -- Dividends received from subsidiaries 100 130 -------- -------- Cash provided by (used in) investing activities (461) 86 -------- -------- Net cash flow (67) 67 Cash and cash equivalents, beginning of year 67 -- -------- -------- Cash and cash equivalents, end of year $ -- $ 67 ======== ======== Supplemental Disclosure of Cash Flow Information: Cash dividends received from subsidiaries $ 200 $ 130 ======== ======== Property dividends received from subsidiaries $ 2 $ 56 ======== ======== 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 7, 2000 Stephen L. Baum Vice Chairman, President, Chief Operating Officer /s/ Stephen L. Baum March 7, 2000 Principal Financial Officer: Neal E. Schmale Executive Vice President, Chief Financial Officer /s/ Neal E. Schmale March 7, 2000 Principal Accounting Officer: Frank H. Ault Vice President and Controller /s/ Frank H. Ault March 7, 2000 Directors: Richard D. Farman, Chairman /s/ Richard D. Farman March 7, 2000 Stephen L. Baum, Vice Chairman /s/ Stephen L. Baum March 7, 2000 Hyla H. Bertea, Director /s/ Hyla H. Bertea March 7, 2000 Ann L. Burr, Director /s/ Ann L. Burr March 7, 2000 Herbert L. Carter, Director /s/ Herbert L. Carter March 7, 2000 Richard A. Collato, Director /s/ Richard A. Collato March 7, 2000 Daniel W. Derbes, Director /s/ Daniel W. Derbes March 7, 2000 Wilford D. Godbold, Jr., Director /s/ Wilford D. Godbold, Jr. March 7, 2000 Robert H. Goldsmith, Director /s/ Robert H. Goldsmith March 7, 2000 William D. Jones, Director /s/ William D. Jones March 7, 2000 Ignacio E. Lozano, Jr., Director /s/ Ignacio E. Lozano, Jr. March 7, 2000 Ralph R. Ocampo, Director /s/ Ralph R. Ocampo March 7, 2000 William G. Ouchi, Director /s/ William G. Ouchi March 7, 2000 Richard J. Stegemeier, Director /s/ Richard J. Stegemeier March 7, 2000 Thomas C. Stickel, Director /s/ Thomas C. Stickel March 7, 2000 Diana L. Walker, Director /s/ Diana L. Walker March 7, 2000
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 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/Southern California Gas - ------------------------------------------- 4.07 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). 4.08 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). 4.09 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). 4.10 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). 4.11 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). 4.12 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). 4.13 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). 4.14 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). 4.15 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). 4.16 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)). Compensation Sempra Energy - ------------- 10.07 Sempra Energy Supplemental Executive Retirement Plan as amended and restated effective July 1, 1998 (1998 Form 10-K Exhibit 10.09). 10.08 Sempra Energy Deferred Compensation Agreement for Directors effective June 1, 1998 (1998 Form 10-K Exhibit 10.10). 10.09 Sempra Energy Executive Incentive Plan effective June 1, 1998 1998 Form 10-K Exhibit 10.11). 10.10 Sempra Energy Executive Deferred Compensation Agreement effective June 1, 1998 (1998 Form 10-K Exhibit 10.12). 10.11 Sempra Energy Retirement Plan for Directors effective June 1, 1998 (1998 Form 10-K Exhibit 10.13). 10.12 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)). 10.13 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)). San Diego Gas & Electric (SDG&E) - -------------------------------- 10.14 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 - --------------------------------------------------- 10.15 Pacific Enterprises Employee Stock Ownership Plan and Trust Agreement as amended effective October 1, 1992 (Pacific Enterprises 1992 Form 10-K Exhibit 10.18). Financing Enova Corporation and San Diego Gas & Electric (SDG&E) - ------------------------------------------------------ 10.16 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). 10.17 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 (Enova 1996 Form 10-K Exhibit 10.31). 10.18 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 (Enova 1996 Form 10-K Exhibit 10.32). 10.19 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). 10.20 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). 10.21 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). 10.22 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). 10.23 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). 10.24 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 (Enova 1996 Form 10-K Exhibit 10.41). 10.25 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). 10.26 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 Transportation Enova Corporation and San Diego Gas & Electric (SDG&E) - ------------------------------------------------------ 10.27 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). 10.28 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). 10.29 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) - ------------------------------------------------------ 10.30 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). 10.31 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). 10.32 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). 10.33 Amendment No. 1 to the Qualified CPUC Decommissioning Master Trust Agreement dated September 22, 1994 (see Exhibit 10.32 herein)(1994 SDG&E Form 10-K Exhibit 10.56). 10.34 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 10.32 herein)(1994 SDG&E Form 10-K Exhibit 10.57). 10.35 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 10.32 herein)(1996 SDG&E Form 10-K Exhibit 10.59). 10.36 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 10.32 herein)(1996 SDG&E Form 10-K Exhibit 10.60). 10.37 Fifth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generation Station (see Exhibit 10.32 herein)(1999 SDG&E Form 10-K Exhibit 10.26). 10.38 Sixth Amendment to the San Diego Gas & Electric Company Nuclear Facilities Qualified CPUC Decommissioning Master Trust Agreement for San Onofre Nuclear Generating Station (see Exhibit 10.32 herein)(1999 SDG&E Form 10-K Exhibit 10.27). 10.39 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). 10.40 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 10.39 herein)(1996 Form 10-K Exhibit 10.62). 10.41 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 10.39 herein)(1996 Form 10-K Exhibit 10.63). 10.42 Third 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 10.39 herein)(1999 SDG&E Form 10-K Exhibit 10.31). 10.43 Fourth 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 10.39 herein)(1999 SDG&E Form 10-K Exhibit 10.32). 10.44 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). 10.45 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). 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, 1999, 1998, 1997, 1996 and 1995. Exhibit 13 -- Annual Report to Security Holders 13.01 Sempra Energy 1999 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 21.01 Schedule of Significant Subsidiaries at December 31, 1999. Exhibit 23 -- Independent Auditors' Consent, page 29. Exhibit 27 -- Financial Data Schedules 27.01 Financial Data Schedule for the year ended December 31, 1999. GLOSSARY BCAP Biennial Cost Allocation Proceeding Bcf One Billion Cubic Feet (of natural gas) CEC California Energy Commission 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 EMFs Electric and Magnetic Fields Enova Enova Corporation EPA Environmental Protection Agency FERC Federal Energy Regulatory Commission GCIM Gas Cost Incentive Mechanism IOUs Investor-Owned Utilities ISO Independent System Operator Kwhr Kilowatt Hour Mw Megawatt NRC Nuclear Regulatory Commission PBR Performance-Based Ratemaking/Regulation PE Pacific Enterprises PG&E Pacific Gas and Electric Company PGE Portland General Electric Company PNM Public Service Company of New Mexico PRP Potentially Responsible Party PSEG Public Service Enterprise Group PX Power Exchange ROE Return on Equity ROR Rate of Return SDG&E San Diego Gas & Electric Company SEI Sempra Energy International SET Sempra Energy Trading SoCalGas Southern California Gas Company SONGS San Onofre Nuclear Generating Station Southwest Powerlink A transmission line connecting San Diego to Phoenix and intermediate points UEG Utility Electric Generation WSPP Western Systems Power Pool EX-12 2 COMPUTATION OF RATIOS EXHIBIT 12.1 SEMPRA ENERGY COMPUTATION OF RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK DIVIDENDS (Dollars in millions)
1995 1996 1997 1998 1999 -------- -------- -------- -------- -------- Fixed Charges and Preferred Stock Dividends: Interest $ 227 $ 205 $ 209 $ 210 $ 233 Interest Portion of Annual Rentals 32 28 25 20 10 Preferred dividends of subsidiaries (1) 50 37 31 18 16 -------- -------- -------- -------- -------- Total Fixed Charges and Preferred Stock Dividends For Purpose of Ratio $ 309 $ 270 $ 265 $ 248 $ 259 ======== ======== ======== ======== ======== Earnings: Pretax income from continuing operations $ 665 $ 727 $ 733 $ 432 $ 573 Add: Fixed charges (from above) 309 270 265 248 259 Less: Fixed charges capitalized 6 5 3 3 5 -------- -------- -------- -------- -------- Fixed charges net of capitalized charges 303 265 262 245 254 -------- -------- -------- -------- -------- Total Earnings for Purpose of Ratio $ 968 $ 992 $ 995 $ 677 $ 827 ======== ======== ======== ======== ======== Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends 3.13 3.67 3.75 2.73 3.19 ======== ======== ======== ======== ======== (1) In computing this ratio, "Preferred dividends of subsidiaries" represents the before-tax earnings necessary to pay such dividends, computed at the effective tax rates for the applicable periods.
EX-13 3 ANNUAL REPORT TO SECURITY HOLDERS EXHIBIT 13.01 MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION This section includes management's discussion and analysis of operating results from 1997 through 1999, and provides 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 in San Diego County and southern Orange County, and Southern California Gas Company (SoCalGas), the nation's largest natural gas distribution utility, serving 5 million meters throughout most of Southern California and part of central California. Together, the two utilities serve approximately 7 million meters. In addition, Sempra Energy owns and operates other regulated and unregulated subsidiaries. Sempra Energy Trading is engaged in the wholesale trading and marketing of natural gas, power and petroleum. Sempra Energy International develops, operates and invests in energy- infrastructure systems and power-generation facilities outside the United States. Sempra Energy Financial invests in limited partnerships that own 1,250 affordable-housing properties throughout the United States. Through other subsidiaries, the company owns and operates centralized heating and cooling for large building complexes, and is involved in nonutility electric generation, domestic energy-utility operations and other energy-related products and services. STRATEGIC DIRECTION Diversified utility companies, including the company, have experienced and will continue to experience a significant increase in the level of competition in the utility and energy services markets over time. A steady move away from a regulated-monopoly, energy-supply structure toward a more competitive structure has affected the utility industry for nearly two decades. During the past decade, various state and federal regulatory changes have occurred and a significant number of states have begun to implement legislative initiatives to permit retail customers to choose their energy supply provider. The company continues to refine its business strategies for the following segments of the energy services industry: regulated delivery services, international, wholesale trading, retail energy services, electric generation and technology ventures. The company plans to pursue the following initiatives to enhance its business model and create sustainable earnings growth. SDG&E and SoCalGas plan to focus on their core distribution businesses, promoting competition in retail markets and efficiency in the delivery-services business. Sempra Energy International will continue to develop electric and gas distribution systems in Nova Scotia, Mexico and portions of South America, while evaluating opportunities to enhance its existing businesses with additional investments. Sempra Energy Trading plans to continue to build and enhance its natural gas, petroleum and electric-wholesale-trading capability in North America, Europe and Asia. In addition, the company and its nonutility subsidiaries plan to provide integrated energy services to mass-market, commercial and industrial retail customers in domestic and international markets. To support its customer-focused activities, the company plans to continue to invest in electric-generation assets, either through development or acquisition. The company also has made investments and is developing new businesses in the information-systems and communications fields. The company believes that all of these businesses will complement and broaden its offerings to utility customers in retail markets. One of the company's objectives is to generate one-third of its consolidated earnings from its unregulated businesses by the end of 2003. The company cannot provide assurance that this objective will be achieved. Based upon this integrated approach to the energy marketplace, the company will seek to achieve long-term returns on shareholder capital that exceed the returns that have been historically available for state-regulated utility businesses. At the same time, the company's business risks are expected to increase, resulting in an increase in the potential volatility in revenue and income streams. As a complement to its business strategy, the company has developed financial initiatives that are intended to increase the company's financial and operating flexibility and to further position the company for the increasingly competitive utility and energy services markets. Accordingly, the company reduced the quarterly dividend payable on shares of its common stock, commencing with the dividend payable in the second quarter of 2000, to $0.25 per share ($1.00 annualized rate) from its previous level of $0.39 per share ($1.56 annualized rate). Reducing the dividend rate improves the company's financial flexibility going forward. It also positions the company's common stock for potential increased growth in market value by retaining a proportionately higher level of earnings for reinvestment in the business. On March 6, 2000, as a result of a "Dutch Auction," the company repurchased approximately 36 million shares of its common stock, representing approximately 15 percent of its outstanding common stock, at a price of $20 per share. The stock repurchase was financed by issuing approximately $700 million in additional long- term senior notes of the company and mandatorily redeemable trust- preferred securities through underwritten public offerings. It financed the remaining $35 million necessary to repurchase the shares with the issuance by a subsidiary, Sempra Energy Holdings, of short-term commercial paper notes, guaranteed by the company. These transactions increased the financial leverage employed by the company in its capital structure. The company expects to maintain a strong investment grade credit rating on its debt and preferred securities and, following the announcement of the tender offer for the approximately 36 million shares and the related financing, rating agencies reaffirmed the ratings for the company's securities and those of its utility subsidiaries. However, these ratings are subject to periodic review by the rating agencies and may change from time to time. BUSINESS-COMBINATION COSTS Sempra Energy was formed to serve as a holding company for Pacific Enterprises ("PE," the parent corporation of SoCalGas) and Enova Corporation ("Enova," the parent corporation of SDG&E) in connection with a business combination that became effective on June 26, 1998 (the PE/Enova business combination). 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. The preferred stock of PE remained outstanding. The combination was a tax-free transaction. In January 1998, PE and Enova jointly acquired CES/Way International, Inc., which was subsequently renamed Sempra Energy Services, as described under "Investments." On June 21, 1999, the company terminated its agreement to acquire KN Energy, Inc. Expenses incurred in connection with these events are $14 million, aftertax, and $85 million, aftertax, for the years ended December 31, 1999 and 1998, respectively. The costs consist primarily of employee-related costs, and investment banking, legal, regulatory and consulting fees. See Note 1 of the notes to Consolidated Financial Statements for additional information. CAPITAL RESOURCES AND LIQUIDITY The company's utility operations continue to be a major source of liquidity. In addition, working capital and other requirements are met primarily through the issuance of short-term and long-term debt. Cash requirements at the utilities primarily consist of investments in plant. Nonutility cash requirements include investments in Sempra Energy Trading, Sempra Energy International and other ventures. Additional information on sources and uses of cash during the last three years is summarized in the following condensed statements of consolidated cash flows: - ----------------------------------------------------------------------- SOURCES AND (USES) OF CASH Year Ended December 31 (Dollars in millions) 1999 1998 1997
- ----------------------------------------------------------------------- Operating Activities $1,188 $1,323 $ 918 ------------------------ Investing Activities: Net proceeds from sale of assets 466 - - Capital expenditures (589) (438) (397) Acquisitions of subsidiaries (639) (191) (206) Other (27) (50) 1 ------------------------ Total Investing Activities (789) (679) (602) ------------------------ Financing Activities: Common dividends (368) (325) (301) Sale of common stock 3 34 17 Repurchase of common stock - (1) (122) Redemption of preferred stock - (75) - Long-term debt - net (110) (356) 382 Short-term debt - net 139 (311) 92 ----------------------- Total Financing Activities (336) (1,034) 68 ----------------------- Increase (decrease) in cash and cash equivalents $ 63 $ (390) $ 384 - -----------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES The decrease in cash flows from operating activities in 1999 was primarily due to the completion of the recovery of SDG&E's stranded costs and to reduced revenues - both the result of the sale of SDG&E's fossil power plants and combustion turbines in the second quarter of 1999 - and a return to ratepayers of the previously overcollected regulatory balancing accounts of SoCalGas. This decrease was partially offset by lower business-combination expenses and lower income-tax payments in 1999. See additional discussion on the sale of the power plants in Note 14 of the notes to Consolidated Financial Statements for additional information. The increase in cash flows from operating activities in 1998 was primarily due to lower working-capital requirements for natural gas operations. This was caused by higher throughput compared to 1997, combined with natural gas costs that were lower than amounts being collected in rates, resulting in overcollected regulatory balancing accounts at year-end 1998. This increase was partially offset by business-combination expenses. The fluctuation in cash flows from operations was also affected by electric-industry restructuring and increased revenue offset by the 10-percent rate reduction reflected in customers' bills in 1998. These are discussed in Note 14 of the notes to Consolidated Financial Statements. CASH FLOWS FROM INVESTING ACTIVITIES Cash flows from investing activities primarily represent capital expenditures and investments in new businesses. For 1999, cash flows from investing activities include proceeds from the sale of SDG&E assets. The South Bay Power Plant was sold to the San Diego Unified Port District for $110 million. The Encina Power Plant and 17 combustion-turbine generators were sold to Dynegy, Inc. and NRG Energy, Inc. for $356 million. See additional discussion in Note 14 of the notes to Consolidated Financial Statements. Capital Expenditures Capital expenditures were $151 million higher in 1999 compared to 1998 due to investments in gas distribution facilities in Mexico, a gas system expansion at SDG&E and additional improvements to the electric-distribution system. 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 and improvements to the electric-distribution system. This increase was partially offset by lower capital spending at SoCalGas. Capital expenditures at the utilities are estimated to be $525 million in 2000 and will be financed primarily by internally generated funds. Investments In June 1999, the company and PSEG Global (PSEG) jointly acquired 90 percent of Chilquinta Energia S.A. (Energia). In January 2000, the company and PSEG purchased an additional 9.75 percent of Chilquinta Energia S.A., increasing their total holdings to 99.98 percent, at a total cost of $840 million. In September 1999, the company and PSEG completed their acquisition of 47.5 percent of Luz Del Sur S.A., a Peruvian electric company, for $108 million. This acquisition, combined with the 37 percent already owned through Energia, increased the companies' total joint ownership to 84.5 percent of Luz del Sur S.A. In March 1998, the company 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. In June 1999, the company contributed capital to Sodigas Pampeana S.A. and Sodigas Sur S.A. to retire $32 million of debt. See further discussion of international operations in "International Operations" below and in Note 3 of the notes to Consolidated Financial Statements. 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. As noted above, Sempra Energy 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 the latter half of 1999, CES/Way's name was changed to Sempra Energy Services. Sempra Energy's level of investments, excluding capital expenditures, in the next few years may vary substantially and will depend on the level of opportunities available in unregulated business that are expected to provide desirable rates of return. CASH FLOWS FROM FINANCING ACTIVITIES Net cash used in financing activities decreased in 1999 from 1998 levels primarily due to lower long-term and short-term debt repayments, greater long-term and short-term debt issuances and the repurchase of preferred stock in 1998. Net cash used in financing activities increased in 1998 from 1997 levels due to greater short-term 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. Long-Term and Short-Term Debt In 1999, cash was used for the repayment of $28 million of first- mortgage bonds, $66 million of rate-reduction bonds and $82 million in unsecured notes. The long-term debt issued in 1999 related primarily to the purchase of Chilquinta Energia S.A. See additional discussion in Note 3 of the notes to Consolidated Financial Statements. The increase in short-term debt primarily represents borrowing through Sempra Energy Holdings (SEH), the intermediate holding company for many of the company's nonutility subsidiaries, to partially finance acquisitions by Sempra Energy International (SEI). 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. 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 connection with the issuance of the rate-reduction bonds, SDG&E has $58 million of temporary investments that will be maintained into the future to offset, for regulatory purposes, a like amount of long-term debt since this was more cost-effective than redeeming low-rate debt. The specific debt series being offset consists of variable-rate IDBs. The California Public Utilities Commission (CPUC) has approved specific ratemaking treatment that 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 $58 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 $58 million and the level of IDBs being offset will be reduced by the same amount. Stock Purchases and Redemptions In February 2000, the company repurchased approximately 36 million shares of its common stock at a price of $20.00 per share. This is more fully described above under "Strategic Direction." The company, through PE and Enova, repurchased $1 million and $122 million of common stock in 1998 and 1997, respectively. There were no common stock repurchases in 1999. On February 2, 1998, SoCalGas redeemed all outstanding shares of its 7 3/4 percent Series Preferred Stock at a cost of $25.09 per share, or $75 million including accrued dividends. Dividends Dividends paid on common stock amounted to $368 million in 1999, compared to $325 million in 1998 and $301 million in 1997. The increases in 1999 and 1998 are 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 previously paid by PE. On January 26, 2000, the company announced a reduction in the quarterly dividend payable on shares of its common stock to $0.25 per share ($1.00 annualized rate) from its previous level of $0.39 per share ($1.56 annualized rate), commencing with the dividend for the second quarter of 2000. 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 Total capitalization at December 31, 1999, was $6.4 billion. The debt-to-capitalization ratio was 50 percent at December 31, 1999. Activities in 1999 include an increase in debt related to the acquisition of Chilquinta Energia S.A., offset by an increase in common equity due to the settlement related to the 1992 quasi- reorganization (QR) of Pacific Enterprises. See Notes 2 and 17 of the notes to Consolidated Financial Statements for further discussion of the QR and concerning the recent change in the debt- to-capitalization ratio, respectively. If the stock repurchase and the related financing had occurred at December 31, 1999, the debt- to-capitalization ratio would have been 62 percent. CASH AND CASH EQUIVALENTS Cash and cash equivalents were $487 million at December 31, 1999. This cash is available for investment in domestic and international projects consistent with the company's strategic direction, the retirement of debt, the repurchase of common stock, the payment of dividends and other corporate purposes. The company anticipates that operating cash required in 2000 for capital expenditures, common stock dividends and debt payments will be provided by cash generated from operating activities and existing cash balances. Cash needed for the tender offer was obtained through the issuance of $500 million of long-term notes and $200 million of mandatorily redeemable trust-preferred securities. The dividend reduction, combined with fewer shares outstanding (due to the company's tender offer), will result in additional cash flow in 2000. This increased cash flow will be partially offset by higher debt-service costs. In addition to cash from ongoing operations, the company has multiyear credit agreements that permit term borrowings of up to $1.4 billion, of which $182 million is outstanding at December 31, 1999. For further discussion, see Note 4 of the notes to Consolidated Financial Statements. Management believes that the sources of funding described above are sufficient to meet short-term and long-term liquidity needs. RESULTS OF OPERATIONS 1999 Compared to 1998 Net income for 1999 increased to $394 million, or $1.66 per share of common stock (diluted), from $294 million, or $1.24 per share of common stock (diluted), for 1998. The increase is primarily due to higher earnings at the California utilities (due to lower business-combination costs), Sempra Energy Trading, Sempra Energy Financial and Sempra Energy International. See additional discussion in "California Utility Operations," "Other Operations" and "International Operations." For the fourth quarter of 1999, net income increased to $105 million, or $0.44 per share of common stock (diluted), from $85 million, or $0.36 per share of common stock (diluted), for the fourth quarter of 1998. The increase is primarily due to higher earnings at Sempra Energy Trading and Sempra Energy International. In 1999, book value per share increased to $12.58 from $12.29 in 1998, primarily due to the settlement of QR issues previously discussed. 1998 Compared to 1997 Net income for 1998 decreased to $294 million, or $1.24 per share of common stock (diluted), from $432 million, or $1.82 per share of common stock (diluted), for 1997. The decrease in net income is primarily due to the business- combination costs and a lower base margin established at SoCalGas in its Performance-Based Regulation (PBR) decision which became effective on August 1, 1997, as further described in Note 14 of the notes to Consolidated Financial Statements. Business-combination expenses were $85 million ($0.36 per share) and $20 million ($0.08 per share), aftertax, for 1998 and 1997, respectively. For the fourth quarter of 1998, net income decreased from the fourth quarter of 1997, due to awards for PBR and demand-side management programs in 1997, electric seasonality effects compared to 1997, and the factors that affected the annual comparison. In 1998, book value per share decreased to $12.29 from $12.56, due to common dividends' exceeding net income, which was lower than normal due to the business-combination expenses. California 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 received approval from the CPUC for Performance-Based Ratemaking (PBR). Under PBR, income potential is tied to achieving or exceeding specific performance and productivity measures, rather than to expanding utility plant 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), which obtains power from qualifying facilities, from nuclear units and, lastly, from the lowest-bidding suppliers. The PX serves as a wholesale power pool, allowing all energy producers to participate competitively. An Independent System Operator (ISO) schedules power transactions and access to the transmission system. The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. The CPUC is studying the issue of restructuring for sales to core customers. See additional discussion of electric-industry and natural gas- industry restructuring below in "Industry Restructuring" and in Note 14 of the notes to Consolidated Financial Statements. - ---------------------------------------------------------------------------------------------- Gas Sales, Transportation & Exchange Transportation Gas Sales & Exchange Total (Dollars in millions, volumes in billion cubic feet) Throughput Revenue Throughput Revenue Throughput Revenue
- ---------------------------------------------------------------------------------------------- 1999: Residential 313 $2,091 3 $10 316 $2,101 Commercial and Industrial 105 560 338 258 443 818 Utility Electric Generation* 18 7 218 83 236 90 Wholesale 23 11 23 11 ---------------------------------------------------------- 436 $2,658 582 $362 1,018 3,020 Balancing accounts and other (96) -------- Total $2,924 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 - ---------------------------------------------------------------------------------------------- *The portion representing SDG&E's sales to its electric generation operations includes margin only.
- ---------------------------------------------------------------------------------------------- ELECTRIC DISTRIBUTION 1999 1998 1997 (Dollars in millions, Volumes Revenue Volumes Revenue Volumes Revenue volumes in millions of Kwhrs)
Residential 6,327 $ 663 6,282 $ 637 6,125 $ 684 Commercial 6,284 592 6,821 643 6,940 680 Industrial 2,034 154 3,097 233 3,607 268 Direct access 3,212 118 964 44 - - Street and highway lighting 73 7 85 8 76 7 Off-system sales 383 10 706 15 4,919 116 --------------------------------------------------- 18,313 1,544 17,955 1,580 21,667 1,755 Balancing accounts and other 274 285 14 --------------------------------------------------- Total 18,313 $1,818 17,955 $1,865 21,667 $1,769 - ----------------------------------------------------------------------------------------------
1999 Compared to 1998 Utility natural gas revenues increased 5 percent in 1999 primarily due to lower overcollections in 1999 (see discussion of balancing accounts under "Accounting Standards" herein and in Note 2 of the notes to Consolidated Financial Statements) and higher utility electric-generation (UEG) revenues, partially offset by a decrease in residential and commercial and industrial revenues. The increase in UEG revenues was primarily due to the 1999 sale of SDG&E's fossil fuel generating plants, since revenue now includes the selling price of the natural gas instead of just the margin, because the sales are now to unrelated parties. The decrease in residential and commercial and industrial revenues is due to lower natural gas rates. Electric revenues decreased 3 percent in 1999 compared to 1998, primarily due to the decrease in base electric rates from the completion of stranded cost recovery (described in Note 14 of the notes to Consolidated Financial Statements). The company's cost of natural gas distributed increased 22 percent in 1999, largely due to an increase in the average price of natural gas purchased. As discussed in Note 14 of the notes to Consolidated Financial Statements, PX/ISO power revenues have been netted against purchased-power expense, including purchases from the PX/ISO. The PX/ISO began operations on March 31, 1998. Depreciation and amortization expense decreased 4 percent in 1999, primarily due to the midyear completion of the accelerated recovery of generation assets. Operating expenses decreased 9 percent in 1999, primarily due to the lower business-combination costs (none in 1999 compared to $117 million in 1998). 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 price 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 Competitive Transition Cost (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 ISO. These increases 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 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. The company's cost of natural gas distributed decreased 18 percent in 1998, largely due to a decrease in the average price of natural gas purchased, partially offset by increases in sales volume. Depreciation and amortization expense increased 49 percent in 1998, primarily due to the accelerated recovery of stranded costs via the CTC. The earnings impact of the increase is offset by CTC revenue as discussed above. Operating expenses increased 16 percent in 1998, primarily due to the higher business-combination costs ($117 million in 1998, compared to $11 million in 1997). INTERNATIONAL OPERATIONS Sempra Energy International (SEI) was formed in June 1998 to develop, operate and invest in energy-infrastructure systems and power-generation facilities outside the United States. SEI now has interests in natural gas and/or electric transmission and distribution projects in Mexico, Argentina, Chile, Peru, Uruguay and Canada, and is pursuing other projects in Latin America. As previously discussed, SEI and PSEG announced the completion of the joint purchase of Chilquinta Energia S.A. and the acquisition of an additional 47.5 percent of the outstanding shares of Luz del Sur S.A., a Peruvian electric company. See Note 3 of the notes to Consolidated Financial Statements for a discussion of the acquisition of Chilquinta Energia S.A. and Luz del Sur S.A. As noted above under "Investments," PE increased its investment in Sodigas Pampeana S.A. and Sodigas Sur S.A. in 1998 and 1999. These natural gas 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 owns 60 percent of Distribuidora de Gas Natural de Mexicali, S. de R.L. de C.V. (DGN-Mexicali), a Mexican company that holds 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. It will invest up to $25 million to provide service to 25,000 customers during the first five years of operation. SEI owns 95 percent of 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, it acquired ownership of a 16-mile transmission pipeline serving 20 industrial customers. It will invest nearly $50 million to provide service to 50,000 customers in the first five years of operation. In May 1999, SEI was awarded a 30-year license to build and operate a natural gas distribution system in the La Laguna-Durango zone in north-central Mexico. SEI will invest over $40 million in the project during the first five years of operation. In August 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 provides for delivery of up to 300 million cubic feet per day of natural gas and construction of a 23-mile pipeline from the U.S.-Mexico border to the plant. Construction of the pipeline is anticipated to be completed by mid-2000 at a cost of $35 million. The pipeline will also serve as a link for a natural gas distribution system in Tijuana, Baja California, between San Diego and Rosarito. Net income for international operations in 1999 was $10 million compared to net losses of $4 million and $9 million, aftertax, for 1998 and 1997, respectively. The increase in net income for 1999 was primarily due to income from Chilquinta Energia S.A., and lower operating costs and increased sales (as a result of colder weather) in Argentina. OTHER OPERATIONS Sempra Energy Trading (SET), a leading natural gas, petroleum and power marketing firm headquartered in Stamford, Conn., was acquired on December 31, 1997. In addition to the transactions described in "Market Risk" herein, SET also enters into long-term structured transactions, such as the one supporting the SEI agreement referred to in "International Operations" above. For the year ended December 31, 1999, SET recorded net income of $32 million from operations and net income of $19 million after amortization of acquisition costs. This is compared to 1998 net income of $1 million from operations and a net loss of $13 million after amortization of acquisition costs. The increase in net income is primarily due to greater penetration of all customer segments, resulting in higher volumes traded in 1999. In addition, new European crude oil and natural gas trading contributed significantly to SET's 1999 earnings. Sempra Energy Financial (SEF) invests as a limited partner in affordable-housing properties and alternative-fuel projects. SEF's portfolio includes 1,250 properties throughout the United States, Puerto Rico and the Virgin Islands. These investments are expected to provide income-tax benefits (primarily from income-tax credits) over a 10-year period. SEF recorded net income of $28 million and $20 million in 1999 and 1998, respectively. This is expected to decline as the various 10-year periods expire, unless SEF makes sufficient new investments. SEF's future investment policy is dependent on the company's future income-tax position. OTHER INCOME, INTEREST EXPENSE AND INCOME TAXES Other Income Other income, which primarily consists of interest income from short-term investments, equity earnings from unconsolidated South American subsidiaries and interest on regulatory-balancing accounts, increased to $75 million in 1999 from $34 million in 1998. The increase is primarily due to equity earnings from unconsolidated subsidiaries. Other income decreased in 1998 to $34 million from $46 million in 1997, a result of lower interest income from short-term investments. Interest Expense Interest expense for 1999 increased to $229 million in 1999 from $197 million in 1998. The increase is primarily due to interest expense on the excess rate-reduction bond liability (see additional discussion in "Factors Influencing Future Performance - Electric Rates" below). Interest expense for 1998 increased slightly to $197 million from $194 million in 1997. Income Taxes Income-tax expense was $179 million, $138 million and $301 million for 1999, 1998 and 1997, respectively. The effective income-tax rates were 31 percent, 32 percent and 41 percent for the same periods. The increase in income-tax expense for 1999 compared to 1998 is due to the increase in income before taxes, partially offset by the charitable contribution to the San Diego Unified Port District in connection with the sale of the South Bay generating plant. The decrease in income-tax expense for 1998 compared to 1997 is primarily due to the decrease in income before taxes, combined with an increase in affordable-housing tax credits. FACTORS INFLUENCING FUTURE PERFORMANCE Base results of the company in the near future will depend primarily on the results of SDG&E and SoCalGas. Earnings growth and fluctuations will depend on changes in the utility industry and activities at SEI, SET and other businesses. Because of the ratemaking and regulatory process, electric- and natural gas- industry restructuring, the changing energy marketplace and these other businesses, there are several factors that will influence future financial performance. These factors are summarized below. Chilquinta Energia S.A. and Luz del Sur S.A. Acquisitions In June 1999, SEI and PSEG announced the completion of the joint purchase of Chilquinta Energia S.A. In September 1999, SEI and PSEG completed the acquisition of 47.5 percent of the outstanding shares of Luz del Sur S.A. See "Business Combinations" above, Note 3 of the notes to Consolidated Financial Statements and "International Operations" below for a discussion of the acquisition of Chilquinta Energia S.A. and Luz del Sur S.A. Nova Scotia In December 1999, Sempra Atlantic Gas (SAG), a subsidiary of SEI, was awarded a 25-year franchise by the provincial government of Nova Scotia to build and operate a natural gas-distribution system in Nova Scotia. SAG plans to invest $700 million to $800 million over the next seven years to build the system, which will make natural gas available to 78 percent of the 350,000 households in Nova Scotia. Construction of the system is expected to begin in mid-2000, and delivery of natural gas is expected to begin by the end of 2000. 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 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. The PX serves as a wholesale power pool allowing all energy producers to participate competitively. Thus far, electric-industry deregulation has been confined to generation. Transmission and distribution have remained subject to traditional cost-of-service and performance-based-ratemaking regulation. However, the CPUC is exploring the possibility of opening up electric distribution to competition. During 2000, the CPUC will consider whether any changes should be made in electric- distribution regulation. A CPUC staff report on this issue will be submitted to the CPUC in the second quarter of 2000. SDG&E and SoCalGas will actively participate in this effort. See Note 14 of the notes to Consolidated Financial Statements for additional information. On December 20, 1999, the Federal Energy Regulatory Commission (FERC) issued "Order 2000" concerning the formation of Regional Transmission Organizations (RTOs). The rule generally requires all public utilities that own, operate or control interstate transmission to file by October 15, 2000, a proposal for an RTO. Public utilities that are members of an existing, FERC-approved regional entity must file by January 15, 2001. The rule states that RTOs will be operational by December 15, 2001, and will address many issues to improve the transmission of energy. See additional discussion in Note 14 of the notes to Consolidated Financial Statements. The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. On January 21, 1998, the CPUC released a staff report initiating a proceeding 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's natural gas consumers. In August 1998, California enacted a law prohibiting the CPUC from enacting any natural gas industry-restructuring decision for core (residential and small-commercial) customers prior to January 1, 2000. During the implementation moratorium, the CPUC has held hearings throughout the state and intends to give the legislature a draft ruling before adopting a final market-structure policy. SDG&E and SoCalGas have been actively participating in this effort and have argued in support of competition intended to maximize benefits to customers rather than to protect competitors. In October 1999, the state of California enacted a law (AB 1421) that requires that gas utilities provide "bundled basic gas service" (including transmission, storage, distribution, purchasing, revenue- cycle services and after-meter services) to all core customers, unless the customer chooses to purchase gas from a nonutility provider. The law prohibits the CPUC from unbundling distribution- related gas services (including meter reading and billing) and after-meter services (including leak investigation, inspecting customer piping and appliances, pilot relighting and carbon monoxide investigation) for most customers. The objective is to preserve both customer safety and customer choice. 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. In June 1999, SDG&E completed the recovery of a majority of its stranded costs. The recovery was affected by, among other things, the sale of SDG&E's fossil power plants and combustion turbines during the quarter ended June 30, 1999. Costs related to the above- market portion of qualifying facilities and other purchased-power contracts that were in effect at December 31, 1995, and the San Onofre Nuclear Generating Station (SONGS) will continue to be recovered in rates. See Note 14 of the notes to Consolidated Financial Statements for additional information. Electric-Generation Assets In 1998, 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 from which utilities throughout the Western United States purchase. 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, is expected to be operational in the second quarter of 2000. Electric Rates AB 1890 provided for a 10-percent reduction in rates for residential and small-commercial customers beginning in January 1998 and 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. 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. The sizes of the rate-reduction bond issuances were set so as to make the IOUs neutral as to the 10-percent rate reduction, and were based on a four-year period to recover stranded costs. Because SDG&E recovered its stranded costs in only 18 months (due to the greater- than-anticipated plant-sale proceeds), the bond proceeds were greater than needed. Accordingly, SDG&E will return to its customers over $400 million that it has collected or will collect from its customers. The timing of the return will differ from the timing of the collection, but the specific timing of the repayment and the interest rate thereon are the subject of a CPUC proceeding and are expected to be resolved in the second quarter of 2000. This refund will not affect SDG&E's net income, except to the extent that the interest cost associated with the refund (12.63 percent if not reduced as a result of the CPUC proceeding) differs from the return earned by the company on the funds. The bonds and their repayment schedule are unaffected by this refund. AB 1890 also includes a rate freeze for all IOU customers during the CTC period. In connection with completion of its stranded cost recovery (described above and in Note 14 of the notes to Consolidated Financial Statements), SDG&E filed with the CPUC for a mechanism to structure electric rates after the end of the rate freeze. SDG&E received approval to reduce base rates (the noncommodity portion of rates) to all electric customers effective July 1, 1999. The portion of the electric rate representing the commodity cost is simply passed through to customers and will fluctuate with the price of electricity from the PX. Except for the interim protection mechanism described below, customers will no longer be protected from commodity price spikes. In April 1999, SDG&E filed an all-party settlement (including energy service providers, the CPUC's Office of Ratepayer Advocates and the Utility Consumers Action Network) detailing proposed implementation plans for lifting the rate freeze. A CPUC decision adopting the all- party settlement was issued in May 1999 and became effective July 1, 1999. Included in the settlement is an interim customer-protection mechanism for residential and small-commercial customers that capped rates between July 1999 and September 1999, regardless of how high the PX price moved during the period. The resulting undercollection (which amounted to less than $1 million) is being recovered through a balancing account mechanism. The interim rate-freeze period runs until the CPUC issues its decision on the pending legal and policy issues of ending the rate freeze. This decision is expected during the second quarter of 2000. Performance-Based Regulation (PBR) To promote efficient operations and improved productivity and to move away from reasonableness review 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 goals, as well as cost reductions, rather than by relying solely on expanding utility plant 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. 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 ratemaking process, the utility will recover the asset from customers. Regulatory liabilities represent future reductions in revenues for amounts due to customers. See Notes 2 and 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. See Notes 1 and 14 of the notes to Consolidated Financial Statements for additional information. Allowed Rate of Return For 2000, SoCalGas is 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 1999. SDG&E is authorized to earn a rate of return on rate base of 8.75 percent and a rate of return on common equity of 10.6 percent, compared to 9.35 percent and 11.6 percent prior to July 1, 1999, respectively. Either utility can earn more than the authorized rate by controlling costs below approval levels, by experiencing increased volumes of sales not subject to balancing accounts (both of which are subject to revenue sharing, as described in Note 14 of the notes to Consolidated Financial Statements) or by achieving favorable results in certain areas, such as incentive mechanisms, that are not subject to revenue sharing. 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 decisions. The utilities intend to make the efficiency improvements, changes in operations and cost reductions necessary to achieve this objective and earn at least 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 prior to the inception of PBR. See additional discussion of PBR above and in Note 14 of the notes to Consolidated Financial Statements. Noncore Bypass SoCalGas is fully at risk for reductions in noncore volumes due to bypass. However, significant bypass would require construction of additional facilities by competing pipelines. SoCalGas has not had a material reduction in earnings from bypass and it is continuing to reduce its costs to remain competitive and retain its transportation customers. Noncore Pricing To respond to bypass, SoCalGas has received authorization from the CPUC for expedited review of long-term natural 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 will be 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 was limited as a result of the Comprehensive Settlement. The settlement addressed a number of regulatory issues and was approved by the CPUC in July 1994. This treatment will be replaced by the PBR mechanism as adopted in the 1999 BCAP, whereby revenue fluctuations will impact earnings (positively or negatively). See Note 14 of the notes to Consolidated Financial Statements for additional discussion. Excess Interstate-Pipeline Capacity Existing interstate-pipeline capacity into California exceeds current demand by over 1 billion cubic feet (Bcf) per day. This situation has reduced the market value of the capacity well below FERC's 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 0.40 Bcf per day of capacity is marketed at significant discounts. Under existing California regulation, unsubscribed capacity costs associated with the remaining 0.40 Bcf per day are recoverable in customer rates. While including the unsubscribed pipeline cost in rates may impact SoCalGas' ability to compete in competitive markets, SoCalGas does not believe its inclusion will have a significant impact on volumes transported or sold. ENVIRONMENTAL MATTERS The company's operations are subject to federal, state and local environmental laws and regulations governing such things as hazardous wastes, air and water quality, land use, solid-waste disposal, and the protection of wildlife. Most of the potential situations in which the company is faced with environmental issues occur at SoCalGas or SDG&E. For these utilities, capital costs to comply with environmental requirements are generally recovered through the depreciation components of customer rates. The utilities' customers also generally are responsible for 90 percent of the noncapital costs associated with hazardous substances and the normal operating costs associated with safeguarding air and water quality, disposing properly of solid waste, and protecting endangered species and other wildlife. Therefore, the likelihood of the company's financial position or results of operations being adversely affected in a significant amount is remote. The environmental issues currently facing the company or resolved during the latest three-year period include investigation and remediation of SoCalGas' and SDG&E's manufactured-gas sites (14 completed as of December 31, 1999, and 31 to be completed), asbestos and other cleanup at SDG&E's former fossil-fueled power plants (all sold in 1999 and actual or estimated cleanup costs included in the transactions), cleanup of third-party waste-disposal sites used by the company, which has been identified as a Potentially Responsible Party (investigations and remediations are continuing), and mitigation of damage to the marine environment caused by the cooling-water discharge from the San Onofre Nuclear Generating Station (SONGS) Units 2 and 3 (the requirements for enhanced fish protection, a 150-acre artificial reef and restoration of 150 acres of coastal wetlands are in process). MARKET RISK The company's policy is to use derivative financial instruments to reduce its 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 exposes 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 (SET) 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 California utilities 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, 1999, the notional amount of swap transactions associated with the regulated operations totaled $45 million. See Note 10 of the notes to Consolidated Financial Statements for further information regarding these swap transactions. The company's California utilities 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 California utilities is subject to certain limitations imposed by 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 California utilities. 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 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, purpose 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, 1999, 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 have used a combination of fixed-rate and floating-rate debt. Subject to regulatory constraints, interest rate swaps 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 has hedged this foreign currency cash exposure through a swap transaction entered into with a major international bank. The VaR on the company's fixed-rate long-term debt is estimated at approximately $194 million as of December 31, 1999, assuming a one- year holding period. Energy-Price Risk Market risk related to physical commodities is based upon potential fluctuations in natural gas, petroleum and electricity 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 one-day holding period. As of December 31, 1999, the diversified VaR of SET's portfolio was $2.6 million. SDG&E and SoCalGas SDG&E and SoCalGas may, at times, be exposed to limited market risk in their natural gas purchase, sale and storage activities as a result of activities under SDG&E's gas PBR or SoCalGas' Gas Cost Incentive Mechanism. They manage their risk within the parameters of the company's market-risk-management and trading framework. As of December 31, 1999, the total VaR of the utilities' 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. Foreign-Currency-Rate Risk Foreign-currency-rate risk exists by nature of the company's global operations. The company has investments in entities whose functional currency is not the U.S. dollar, which exposes the company to foreign exchange movements, primarily in Latin American currencies. When appropriate, the company may attempt to limit its exposure to changing foreign exchange rates through both operational and financial market actions. These actions may include entering into forward, option and swap contracts to hedge existing exposures, firm commitments and anticipated transactions. As of December 31, 1999, the company had not entered into any such actions. YEAR 2000 ISSUES There were only a few, very minor Year 2000 interruptions to the company's automated systems and applications, suppliers and customers. The company incurred expenses of $48 million (including $7.6 million in 1999) for its Year 2000 readiness effort and expects to incur no additional costs. NEW ACCOUNTING STANDARDS In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivative Instruments and Hedging Activities." In June 1999, the effective date of this statement was deferred for one year. As amended, SFAS 133, which is effective for the company on January 1, 2001, 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 contains statements that are not historical fact and constitute forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. The words "estimates," "believes," "expects," "anticipates," "plans," "intends," "may" and "should" or similar expressions, or discussions of strategy or of plans are intended to identify forward-looking statements that involve risks, uncertainties and assumptions. Future results may differ materially from those expressed in these forward- looking statements. These statements are necessarily based upon various assumptions involving judgments with respect to the future and other risks, 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; exchange rates; energy markets, including the timing and extent of changes in commodity prices; weather conditions; business, regulatory or legal decisions; the pace of deregulation of retail natural gas and electricity delivery; 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. Readers are cautioned not to rely unduly on any forward-looking statements and are urged to review and consider carefully 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 FIVE-YEAR SUMMARY At December 31 or for the years ended December 31 (Dollars in millions except per-share amounts) 1999 1998 1997 1996 1995
- ---------------------------------------------------------------------------------------------- REVENUES AND OTHER INCOME: Gas $ 2,924 $ 2,772 $ 2,964 $ 2,710 $ 2,542 Electric 1,818 1,865 1,769 1,591 1,504 Other 693 378 382 223 155 -------------------------------------------- Total $ 5,435 $ 5,015 $ 5,115 $ 4,524 $ 4,201 -------------------------------------------- Operating income $ 802 $ 629 $ 927 $ 927 $ 886 Net income $ 394 $ 294 $ 432 $ 427 $ 401 Net income per common share: Basic $ 1.66 $ 1.24 $ 1.83 $ 1.77 $ 1.67 Diluted $ 1.66 $ 1.24 $ 1.82 $ 1.77 $ 1.67 Dividends declared per common share $ 1.56 $ 1.56 $ 1.27 $ 1.24 $ 1.22 Pretax income/revenue 10.7% 8.7% 14.5% 16.2% 16.0% Return on common equity 13.3% 10.0% 14.7% 14.9% 14.6% Effective income tax rate 31.2% 31.9% 41.1% 41.3% 39.7% Dividend payout ratio: Basic 94.0% 125.8% 69.4% 70.1% 73.1% Diluted 94.0% 125.8% 69.8% 70.1% 73.1% Price range of common shares 26-17 1/8 29 5/16-23 3/4 * * * AT DECEMBER 31 Current assets $ 3,040 $ 2,458 $ 2,761 $ 1,592 $ 1,520 Total assets $11,270 $10,456 $10,756 $ 9,762 $ 9,837 Current liabilities $ 3,327 $ 2,466 $ 2,211 $ 1,572 $ 1,578 Long-term debt (excludes current portion) $ 2,902 $ 2,795 $ 3,175 $ 2,704 $ 2,721 Shareholders' equity $ 2,986 $ 2,913 $ 2,959 $ 2,930 $ 2,815 Common shares outstanding(in millions) 237.4 237.0 235.6 240.0 240.6 Book value per common share $ 12.58 $ 12.29 $ 12.56 $12.21 $11.70 Price/earnings ratio 10.5 20.5 * * * Number of meters (in thousands): Natural gas 5,725 5,639 5,551 5,501 5,436 Electricity 1,218 1,192 1,178 1,164 1,151 - ---------------------------------------------------------------------------------------------- *Not presented as the formation of Sempra Energy was not completed until June 26, 1998.
STATEMENT OF MANAGEMENT RESPONSIBILITY FOR CONSOLIDATED 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 on the next page. 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, as well as in executive session. 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. Neal E. Schmale Executive Vice President and Chief Financial Officer 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, 1999 and 1998, 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, 1999. 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, 1999 and 1998, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1999, in conformity with generally accepted accounting principles. /S/ DELOITTE & TOUCHE LLP San Diego, California February 4, 2000 (February 25, 2000 as to Note 17) STATEMENTS OF CONSOLIDATED INCOME For the years ended December 31 (Dollars in millions except per-share amounts) 1999 1998 1997
- -------------------------------------------------------------------------------- REVENUES AND OTHER INCOME Utility revenues: Natural gas $2,924 $2,772 $2,964 Electric 1,818 1,865 1,769 Other operating revenues 618 344 336 Other income 75 34 46 ------------------------ Total 5,435 5,015 5,115 ------------------------ Expenses Cost of natural gas distributed 1,164 954 1,168 Purchased power - net 467 260 441 Electric fuel 69 177 164 Operating expenses 1,862 1,872 1,615 Depreciation and amortization 879 929 604 Franchise payments and other taxes 181 182 178 Preferred dividends by subsidiaries 11 12 18 ------------------------ Total 4,633 4,386 4,188 ------------------------ Income Before Interest and Income Taxes 802 629 927 Interest 229 197 194 ------------------------ Income Before Income Taxes 573 432 733 Income taxes 179 138 301 ------------------------ Net Income $ 394 $ 294 $ 432 ------------------------ Net Income Per Share of Common Stock (Basic) $ 1.66 $ 1.24 $ 1.83 ------------------------ Net Income Per Share of Common Stock (Diluted) $ 1.66 $ 1.24 $ 1.82 ------------------------ Common Dividends Declared Per Share $ 1.56 $ 1.56 $ 1.27 - -------------------------------------------------------------------------------- See notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS At December 31 (Dollars in millions) 1999 1998
- -------------------------------------------------------------------------------- ASSETS Current assets: Cash and cash equivalents $ 487 $ 424 Accounts receivable - trade 428 586 Accounts and notes receivable - other 129 159 Income taxes receivable 144 - Deferred income taxes - 93 Energy trading assets 1,539 906 Inventories 148 151 Other 165 139 ----------------- Total current assets 3,040 2,458 ----------------- Investments and other assets: Regulatory assets 670 1,056 Nuclear-decommissioning trusts 551 494 Investments 1,164 548 Other assets 451 459 ----------------- Total investments and other assets 2,836 2,557 ----------------- Property, plant and equipment: Property, plant and equipment 11,127 11,235 Less accumulated depreciation and amortization (5,733) (5,794) ------------------ Total property, plant and equipment - net 5,394 5,441 ------------------ Total assets $11,270 $10,456 - -------------------------------------------------------------------------------- See notes to Consolidated Financial Statements.
CONSOLIDATED BALANCE SHEETS (CONTINUED) At December 31 (Dollars in millions) 1999 1998
- -------------------------------------------------------------------------------- LIABILITIES Current liabilities: Short-term debt $ 182 $ 43 Accounts payable 737 702 Accrued income taxes - 27 Deferred income taxes 67 - Energy trading liabilities 1,365 805 Dividends and interest payable 154 168 Regulatory balancing accounts - net 357 120 Long-term debt due within one year 155 330 Other 310 271 ----------------- Total current liabilities 3,327 2,466 ----------------- Long-term debt 2,902 2,795 Deferred credits and other liabilities: Customer advances for construction 72 72 Post-retirement benefits other than pensions 204 240 Deferred income taxes 615 634 Deferred investment tax credits 106 147 Deferred credits and other liabilities 854 985 ----------------- Total deferred credits and other liabilities 1,851 2,078 ----------------- Preferred stock of subsidiaries 204 204 ----------------- Commitments and contingent liabilities (Note 13) SHAREHOLDERS' EQUITY Common stock 1,966 1,883 Retained earnings 1,101 1,075 Deferred compensation relating to ESOP (42) (45) Accumulated other comprehensive income (39) - ---------------- Total shareholders' equity 2,986 2,913 ---------------- Total liabilities and shareholders' equity $11,270 $10,456 - ------------------------------------------------------------------------------- See notes to Consolidated Financial Statements.
STATEMENTS OF CONSOLIDATED CASH FLOWS For the years ended December 31 (Dollars in millions) 1999 1998 1997
- ------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES Net income $ 394 $ 294 $ 432 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 879 929 604 Portion of depreciation arising from sales of generating plants (303) - - Application of balancing account to stranded costs (66) (86) - Deferred income taxes and investment tax credits (43) (199) (16) Other - net (87) (94) 62 Net change in other working capital components 414 479 (164) ------------------------- Net cash provided by operating activities 1,188 1,323 918 ------------------------- CASH FLOWS FROM INVESTING ACTIVITIES Net proceeds from sales of generating plants 466 - - Expenditures for property, plant and equipment (589) (438) (397) Acquisitions of businesses (639) (191) (206) Other (27) (50) 1 ------------------------- Net cash used in investing activities (789) (679) (602) ------------------------- CASH FLOWS FROM FINANCING ACTIVITIES Common dividends (368) (325) (301) Sale of common stock 3 34 17 Repurchase of common stock - (1) (122) Redemption of preferred stock - (75) - Issuances of other long-term debt 160 75 140 Issuance of rate-reduction bonds - - 658 Payments on long-term debt (270) (431) (416) Increase (decrease) in short-term debt - net 139 (311) 92 ------------------------ Net cash provided by (used in) financing activities (336) (1,034) 68 ------------------------ Increase (Decrease) in Cash and Cash Equivalents 63 (390) 384 Cash and Cash Equivalents, January 1 424 814 430 ------------------------ Cash and Cash Equivalents, December 31 $ 487 $ 424 $ 814 - -------------------------------------------------------------------------------- See notes to Consolidated Financial Statements.
STATEMENTS OF CONSOLIDATED CASH FLOWS (CONTINUED) For the years ended December 31 (Dollars in millions) 1999 1998 1997
- -------------------------------------------------------------------------------- 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 $188 $ 90 $(129) Net trading assets (73) (71) - Inventories 3 (40) (2) Regulatory balancing accounts 303 417 48 Other current assets (26) (26) 41 Accounts payable and other current liabilities 19 109 (122) ------------------------ Net change in other working capital components $414 $479 $(164) ------------------------ SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Cash paid during the year for: Interest (net of amounts capitalized) $281 $211 $193 Income taxes (net of refunds) $168 $366 $274 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 $ 34 $ 36 $126 ----------------------- 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.
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY Deferred Accumulated For the years ended Compensation Other Total December 31, 1999, 1998 and 1997 Comprehensive Common Retained Relating Comprehensive Shareholders' (Dollars in millions) Income Stock Earnings to ESOP Income Equity
- ----------------------------------------------------------------------------------------------------------------------- Balance at December 31, 1996 | $1,953 $1,026 $(49) $ - $2,930 | Net income/comprehensive income $ 432 | 432 432 Common stock dividends declared | (301) (301) Sale of common stock | 17 17 Repurchase of common stock | (122) (122) Long-term incentive plan | 1 1 Common stock released from ESOP | 2 2 --------------|--------------------------------------------------------------------- Balance at December 31, 1997 | 1,849 1,157 (47) - 2,959 | Net income/comprehensive income 294 | 294 294 Common stock dividends declared | (376) (376) Sale of common stock | 34 34 Repurchase of common stock | (1) (1) Long-term incentive plan | 1 1 Common stock released from ESOP | 2 2 --------------|-------------------------------------------------------------------- Balance at December 31, 1998 | 1,883 1,075 (45) - 2,913 | Net income 394 | 394 394 Comprehensive income adjustment: | Foreign-currency translation losses (42) | (42) (42) Available-for-sale securities 12 | 12 12 Pension (9) | (9) (9) ------- | Comprehensive income $ 355 | ------- | Common stock dividends declared | (368) (368) Quasi-reorganization | adjustment (Note 2) | 80 80 Sale of common stock | 2 2 Long-term incentive plan | 1 1 Common stock released from ESOP | 3 3 ---------|-------------------------------------------------------------------- Balance at December 31, 1999 | $1,966 $1,101 $(42) $(39) $2,986 - --------------------------------------------------------------------------------------------------------------------- See notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1 BUSINESS COMBINATION Sempra Energy (the company) was formed as a holding company for Enova Corporation (Enova) and Pacific Enterprises (PE) in connection with a business combination of Enova and PE that was completed on June 26, 1998. As a result of the combination each outstanding share of common stock of Enova was converted into one share of common stock of Sempra Energy, and each outstanding share of common stock of PE was converted into 1.5038 shares of common stock of Sempra Energy. The preferred stock and preference stock of the combining companies and their subsidiaries remained outstanding. 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. 2 SIGNIFICANT ACCOUNTING POLICIES EFFECTS OF REGULATION The accounting policies of the company's principal subsidiaries, San Diego Gas & Electric (SDG&E) and Southern California Gas Company (SoCalGas), conform with generally accepted accounting principles for regulated enterprises and reflect the policies of the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). SDG&E and SoCalGas prepare 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 records a regulatory asset if it is probable that, through the ratemaking process, the utility will recover that asset from customers. Regulatory liabilities represent future reductions in rates for amounts due to customers. To the extent that portions of the utility operations were to be no longer subject to SFAS No. 71, or recovery was to be no longer probable as a result of changes in regulation or the utility's competitive position, the related regulatory assets and liabilities would be written off. In addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets 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. The application of SFAS No. 121 continues to be evaluated in connection with industry restructuring. Information concerning regulatory assets and liabilities is described below in "Revenues and Regulatory Balancing Accounts" and industry restructuring is described 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, 1999, represent net payables of $165 million and $192 million for SoCalGas and SDG&E, respectively. The corresponding amounts at December 31, 1998, were $129 million net payable and $9 million net receivable for SoCalGas and SDG&E, respectively. Prior to 1998, fluctuations in utility earnings 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. 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 was applied to transition cost recovery, and fluctuations in certain costs and consumption levels can now affect earnings from electric operations. In addition, fluctuations in certain costs and consumption levels can affect earnings from SDG&E's gas operations. Additional information on regulatory matters is included in Note 14. 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 also earns trading profits as a dealer by structuring and executing transactions that permit its counterparties to manage their risk profiles, and takes positions in energy markets based on the expectation of future market conditions. These positions include options, forwards, futures and swaps. SET adjusts these derivatives to market each month with gains and losses recognized in earnings. See "Trading Instruments" below and Note 10 for additional information. REGULATORY ASSETS Regulatory assets include unrecovered premium on early retirement of debt, postretirement 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. 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. INVENTORIES Included in inventories at December 31, 1999, are $68 million of utility materials and supplies ($70 million in 1998), and $80 million of natural gas and fuel oil ($81 million in 1998). 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. PROPERTY, PLANT AND EQUIPMENT This primarily represents the buildings, equipment and other facilities used by SoCalGas and SDG&E 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, 1999, are: natural gas operations $7.1 billion, electric distribution $2.5 billion, electric transmission $0.7 billion, and other electric $0.4 billion. The corresponding amounts at December 31, 1998, were essentially the same, except that other electric decreased by $0.5 billion in 1999 in connection with electric-industry restructuring, as described in Note 14. Accumulated depreciation and decommissioning of natural gas and electric utility plant in service at December 31, 1999, are $3.8 billion and $1.9 billion, respectively, and at December 31, 1998, were $3.5 billion and $2.2 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 1999, 1998 and 1997, respectively are: natural gas operations 4.32, 4.32, 4.31, electric generation 8.70, 6.49, 5.60, electric distribution 4.69, 4.49, 4.39, electric transmission 3.50, 3.31, 3.28, and other electric 8.21, 6.29, 6.02. The increases for electric generation reflect the accelerated recovery of generation facilities and the increase in depreciation rates resulting from the 1999 Cost of Service proceeding. See Note 14 for additional discussion of generation facilities and industry restructuring. The remaining cost amounts ($0.4 billion at December 31, 1999, and $0.2 billion at December 31, 1998) consist of various items of property at various other consolidated entities, with various depreciation rates depending on the nature of the items. NUCLEAR-DECOMMISSIONING LIABILITY Deferred credits and other liabilities at December 31, 1999, include $165 million ($146 million in 1998) of accumulated decommissioning costs associated with SDG&E's interest in San Onofre Nuclear Generating Station (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. FOREIGN CURRENCY TRANSLATION The assets and liabilities of the company's foreign operations are generally translated into U.S. dollars at current exchange rates, and revenues and expenses are translated at average exchange rates for the year. Resulting translation adjustments are reflected in a component of shareholders' equity ("accumulated other comprehensive income"). Foreign currency transaction gains and losses are included in consolidated net income. COMPREHENSIVE INCOME SFAS No. 130, "Reporting Comprehensive Income," 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 marketable securities that are classified as available- for-sale. Securities are so classified if the company uses the securities in its cash/asset management program whereby the securities may be sold in connection with interest rate changes and cash requirements. At December 31, 1999, the company had one such investment, which increased in value during 1999. That increase is recognized in the "Statement of Consolidated Changes in Shareholders' Equity." QUASI-REORGANIZATION In 1993, PE divested its merchandising operations and most 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 the quasi- reorganization were favorably resolved in November 1999, including unitary tax issues. Excess reserves of $80 million resulting from the favorable resolution of these issues have been added to shareholders' equity. Other 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. 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. CASH AND CASH EQUIVALENTS Cash equivalents are highly liquid investments with original maturities of three months or less at the date of purchase, or investments that are readily convertible to cash. BASIS OF PRESENTATION Certain prior-year amounts have been reclassified to conform to the current year's presentation. NEW ACCOUNTING STANDARD In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for Derivative Instruments and Hedging Activities," which is effective for the company on January 1, 2001. The statement 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 INTERNATIONAL (SEI) On June 10, 1999, SEI and PSEG Global (PSEG) purchased (on a 50/50 basis) Chilquinta Energia S.A. (Energia) for $840 million. Sempra Energy invested $260 million for the purchase of stock and refinanced $160 million of Energia's long-term debt outstanding. In September 1999, Sempra Energy and PSEG completed their acquisition of 47.5 percent of the outstanding shares of Luz del Sur S.A., a Peruvian electric company. Sempra Energy's share of the transaction was $108 million in cash. This acquisition, combined with the 37 percent already owned through Energia, increased the companies' total joint ownership to 84.5 percent of Luz del Sur S.A. SEI 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 May 1999, SEI was awarded a 30-year license to build and operate a natural gas distribution system in the La Laguna-Durango zone in north-central Mexico. SEI will invest over $40 million in the project during the first five years of operation. 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, the related transportation services in the U.S., and construction of a 23-mile pipeline from the U.S.-Mexico border to the plant. Construction of the pipeline is anticipated to be completed by mid-2000 at a cost of $35 million. The pipeline will also serve as a link for a natural gas distribution system in Tijuana, Baja California. In December 1999 Sempra Atlantia Gas (SAG), a subsidiary of SEI, was awarded a 25-year franchise by the provincial government of Nova Scotia to build and operate a natural gas distribution system in Nova Scotia. SAG plans to invest $700 million to $800 million over the next seven years to build the system, which will make natural gas available to 78 percent of the 350,000 households in Nova Scotia. Construction of the system is expected to begin in mid-2000, and delivery of natural gas is expected to begin by the end of 2000. 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. In June 1999, the company contributed capital to the Argentine companies to retire $32 million of debt. The distribution companies serve 1.2 million customers in central and southern Argentina, respectively, and have a combined throughput of 650 million cubic feet per day. SEMPRA ENERGY TRADING In December 1997, the company acquired Sempra Energy Trading (SET) for $225 million. SET is a wholesale-energy trading company based in Stamford, Conn. 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 expanded 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. As of December 31, 1999, SER has invested $55 million in this 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. The plant is expected to be operational in the second quarter of 2000. SEMPRA ENERGY SERVICES CES/Way International, a national leader in energy-service performance contracting, was acquired in January 1998 and renamed Sempra Energy Services in 1999. Headquartered in Houston, Sempra Energy Services provides energy-efficiency services, including energy audits, engineering design, project management, construction, financing and contract maintenance. 4 SHORT-TERM BORROWINGS PE has a $300 million multiyear credit agreement. SoCalGas has an additional $400 million multiyear 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, 1999, both bank lines of credit were unused. At December 31, 1998, PE had $43 million of bank loans under the credit agreement, which was due and paid in January 1999. SoCalGas' bank line of credit was unused. SDG&E has $205 million of bank lines available to support commercial paper and variable-rate, long-term debt. The credit agreements expire at varying dates from 2000 through 2002 and bear interest at various rates based on market rates and SDG&E's credit rating. SDG&E's bank lines of credit were unused at both December 31, 1999, and 1998. In 1999, Sempra Energy Holdings (SEH), the intermediate holding company for many of the company's nonutility subsidiaries, entered into a $500 million credit agreement that expires in 2000. Borrowings under the agreement bear interest at various rates based on market rates and the credit rating of Sempra Energy. SEH's credit agreement is available to support commercial paper. At December 31, 1999, SEH had $182 million of commercial paper outstanding. 5 LONG-TERM DEBT - -------------------------------------------------------------------------------- December 31 (Dollars in millions) 1999 1998
- -------------------------------------------------------------------------------- LONG-TERM DEBT First-mortgage bonds 7.625% June 15, 2002 $ 28 $ 28 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 68 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 10 Variable rates September 1, 2020 58 58 5.85% June 1, 2021 60 60 8.75% October 1, 2021 150 150 8.5% April 1, 2022 10 10 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 225 250 --------------- Total 1,434 1,462 Rate-reduction bonds 526 592 Debt incurred to acquire limited partnerships, secured by real estate, at 6.8% to 9.0%, payable annually through 2009 284 305 Various unsecured bonds at 5.67% to 8.75% or at variable rates (3.1% to 3.3% at December 31, 1999) payable from 2000 to 2028 495 577 Employee Stock Ownership Plan 130 130 Variable rate debt (9.75% at December 31, 1999) payable 2001 and 2004 160 - Capitalized leases 43 76 -------------- Total 3,072 3,142 -------------- Less: Current portion of long-term debt 155 330 Unamortized discount on long-term debt 15 17 ------------- 170 347 ------------- Total $2,902 $2,795 - -------------------------------------------------------------------------------
Excluding capital leases, which are described in Note 13, maturities of long-term debt are $152 million in 2000, $320 million in 2001, $234 million in 2002, $277 million in 2003, $175 million in 2004 and $1.9 billion thereafter. SDG&E and SoCalGas have CPUC authorization to issue an additional $738 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. SDG&E and SoCalGas may issue additional first- mortgage bonds upon compliance with the provisions of their bond indentures, which permit, among other things, the issuance of an additional $1.4 billion of first-mortgage bonds as of December 31, 1999. During 1999, the company retired $28 million of first-mortgage bonds prior to scheduled maturity. CALLABLE BONDS At SDG&E's or SoCalGas' option, certain bonds may be called at a premium. SoCalGas has no variable-rate bonds. SDG&E has $287 million of variable-rate bonds that are callable at various dates within one year. Of the company's remaining callable bonds, $55 million are callable in the year 2000, $150 million in 2001, $204 million in 2002, $621 million in 2003, and $8 million in 2006. 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. The sizes of the rate-reduction bond issuances were set so as to make the utilities neutral as to the 10-percent rate reduction, and were based on a four-year period to recover stranded costs. Because SDG&E recovered its stranded costs in only 18 months (due to the greater-than-anticipated plant-sale proceeds), its bond proceeds were greater than needed. Accordingly, SDG&E will return to its customers over $400 million that it has collected or will collect from its customers. The timing of the return will differ from the timing of the collection, but the specific timing of the repayment and the interest rate thereon are the subject of a CPUC proceeding and are expected to be resolved in early 2000. This refund will not affect SDG&E's net income, except to the extent that the interest associated with the refund (12.63 percent if not reduced as a result of the CPUC proceeding) differs from the return earned by the company on the funds. The bonds and their repayment schedule are not affected by this refund. UNSECURED DEBT Various long-term obligations totaling $495 million are unsecured. Unsecured bonds totaling $124 million have variable-rate provisions. DEBT OF EMPLOYEE STOCK OWNERSHIP PLAN (ESOP) AND TRUST (TRUST) The Trust covers substantially all of Southern California Gas Company's employees and is used to fund part of the retirement savings plan. The Trust was assumed by Sempra Energy on October 1, 1999, and participation in the ESOP is being expanded to include employees of SDG&E and other affiliates. In November 1999 the $130 million ESOP debt was refinanced using variable-rate (6.59% at December 31, 1999) notes with a 15-year term. However, because the company is required to make proportionate reductions in the debt balance, the average life of the loan will be less than 10 years. Interest on ESOP debt amounted to $6 million in each of 1999, 1998 and 1997. Dividends used for debt service amounted to $5 million in 1999 and 1998, and $3 million in 1997. 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, 1999, 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, 1999, are: - -------------------------------------------------------------------------------- (Dollars in millions) Southwest Project SONGS Powerlink
- -------------------------------------------------------------------------------- Percentage ownership 20 89 Utility plant in service $57 $217 Accumulated depreciation and amortization $25 $111 Construction work in progress $ 7 $ 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. Certain substation equipment at SONGS 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 CPUC and other regulatory bodies. The company's share of decommissioning costs for the SONGS units is estimated to be $432 million in today's dollars, based on a cost study completed in 1998. Cost studies are performed and updated periodically by outside consultants. 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 owner of Unit 1 received the required regulatory approvals to begin decommissioning Unit 1 in January 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 at market value. These values reflect unrealized gains of $164 million and $149 million at December 31, 1999, and 1998, 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 carrying value 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: - -------------------------------------------------------------------------------- For the years ended December 31 1999 1998 1997
- -------------------------------------------------------------------------------- Statutory federal income tax rate 35.0% 35.0% 35.0% Depreciation 7.0 7.5 6.8 State income taxes - net of federal income tax benefit 6.6 7.4 6.7 Tax credits (14.9) (12.9) (5.7) Charitable contribution of plant (4.4) - - Other - net 1.9 (5.1) (1.7) - -------------------------------------------------------------------------------- Effective income tax rate 31.2% 31.9% 41.1% - --------------------------------------------------------------------------------
The components of income tax expense are as follows: - -------------------------------------------------------------------------------- (Dollars in millions) 1999 1998 1997
- -------------------------------------------------------------------------------- CURRENT: Federal $ 72 $278 $236 State 21 89 63 ----------------------- Total 93 367 299 ----------------------- DEFERRED: Federal 79 (165) 1 State 15 (58) 7 ----------------------- Total 94 (223) 8 ----------------------- DEFERRED INVESTMENT TAX CREDITS-NET (8) (6) (6) ---------------------- Total income tax expense $179 $138 $301 - --------------------------------------------------------------------------------
Accumulated deferred income taxes at December 31 result from the following: - -------------------------------------------------------------------------------- (Dollars in millions) 1999 1998
- -------------------------------------------------------------------------------- DEFERRED TAX LIABILITIES: Differences in financial and tax bases of utility plant $ 842 $ 924 Regulatory balancing accounts 166 23 Regulatory assets 69 76 Partnership income 37 27 Other 121 71 ---------------- Total deferred tax liabilities 1,235 1,121 ---------------- DEFERRED TAX ASSETS: Investment tax credits 84 88 General business tax credit carryforward 46 - Comprehensive Settlement (see Note 14) 42 95 Postretirement benefits 69 76 Other deferred liabilities 98 102 Restructuring costs 51 42 Other 160 177 ---------------- Total deferred tax assets 550 580 ---------------- Net deferred income tax liability $ 685 $ 541 - --------------------------------------------------------------------------------
The net liability is recorded on the consolidated balance sheet as follows: - -------------------------------------------------------------------------------- (Dollars in millions) 1999 1998
- -------------------------------------------------------------------------------- Current liability (asset) $ 67 $ (93) Non-current liability 618 634 -------------- Total $685 $541 - --------------------------------------------------------------------------------
The general business tax credit carryforwards expire in 2019. The company has not provided for U.S. income taxes on foreign subsidiaries' undistributed earnings ($49 million at December 31, 1999), which are expected to be reinvested indefinitely. It is not possible to predict the amount of U.S. income taxes that might be payable if these earnings are eventually repatriated. 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 merged with similar plans or modified, and numerous participants have been transferred among plans of related entities. In connection therewith, the company recorded a $66 million special termination benefit in 1998. PENSION AND OTHER POSTRETIREMENT BENEFITS The company sponsors several qualified and nonqualified pension plans and other postretirement benefit plans for its employees. Effective March 1, 1999, the Pacific Enterprises Pension Plan merged with the Sempra Energy Cash Balance Plan. The following tables provide a reconciliation of the changes in the plans' benefit obligations and the fair value of assets over the two years, and a statement of the funded status as of each year end: - -------------------------------------------------------------------------------- Pension Other Postretirement Benefits Benefits - -------------------------------------------------------------------------------- (Dollars in millions) 1999 1998 1999 1998
- -------------------------------------------------------------------------------- WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31: Discount rate 7.75% 6.75% 7.75% 6.75% Expected return on plan assets 8.00% 8.50% 7.85% 8.50% Rate of compensation increase 5.00% 5.00% 5.00% 5.00% Cost trend of covered health-care charges - - 7.75%(1) 8.00%(1) CHANGE IN BENEFIT OBLIGATION: Net benefit obligation at January 1 $ 2,080 $ 2,117 $ 563 $ 531 Service cost 48 55 15 13 Interest cost 142 148 40 36 Plan participants' contributions - - 3 1 Plan amendments - 18 - - Actuarial gains (147) (44) (44) - Special termination benefits - 63 - 3 Gross benefits paid (161) (277) (22) (21) ------------------------------------- Net benefit obligation at December 31 1,962 2,080 555 563 ------------------------------------- CHANGE IN PLAN ASSETS: Fair value of plan assets at January 1 2,796 2,653 443 363 Actual return on plan assets 789 407 96 64 Employer contributions 3 13 28 36 Plan participants' contributions - - 3 1 Gross benefits paid (161) (277) (22) (21) ------------------------------------ Fair value of plan assets at December 31 3,427 2,796 548 443 ------------------------------------ Funded status at December 31 1,465 716 (7) (120) Unrecognized net actuarial gain (1,627) (926) (185) (107) Unrecognized prior service cost 66 73 (12) (13) Unrecognized net transition obligation 3 3 - - ------------------------------------ Net liability at December 31 $ (93) $ (134) $(204) $(240) - ----------------------------------------------------------------------------- (1) Decreasing to ultimate trend of 6.50% in 2004.
The following table provides the components of net periodic benefit cost (income) for the plans: - ---------------------------------------------------------------------------------------------- Other Pension Benefits Postretirement Benefits - ---------------------------------------------------------------------------------------------- For the years ended December 31, 1999 1998 1997 1999 1998 1997 (Dollars in millions)
- ---------------------------------------------------------------------------------------------- Service cost $ 48 $ 55 $ 53 $ 15 $ 13 $ 15 Interest cost 142 148 144 40 36 35 Expected return on assets (206) (196) (178) (32) (24) (22) Amortization of: Transition obligation 1 1 1 2 2 2 Prior service cost 6 6 5 (1) (1) (1) Actuarial (gain) loss (31) (23) (18) 2 - 1 Special termination benefit - 63 13 - 3 2 Settlement credit - (30) - - - - Regulatory adjustment 17 - - 24 9 12 ------------------------------------------------- Total net periodic benefit cost (income) $ (23) $ 24 $ 20 $ 50 $ 38 $ 44 - ----------------------------------------------------------------------------------------------
The following table provides the amounts recognized on the Sempra Energy balance sheet at December 31. - ---------------------------------------------------------------------------------------------- Other Postretirement Pension Benefits Benefits - ---------------------------------------------------------------------------------------------- (Dollars in millions) 1999 1998 1999 1998
- ---------------------------------------------------------------------------------------------- Prepaid benefit cost $ 13 $ - $ - $ - Accrued benefit cost (106) (125) (204) (240) Additional minimum liability (18) (13) - - Intangible asset 6 4 - - Accumulated other comprehensive income, pre-tax 12 - - - ---------------------------------------------- Net liability $ (93) $(134) $(204) $(240) - ----------------------------------------------------------------------------------------------
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percent 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 $10 $(9) Effect on the health care component of the accumulated postretirement benefit obligation $76 $(69) - ----------------------------------------------------------------------
Except for one nonqualified retirement plan, all pension plans had plan assets in excess of accumulated benefit obligations. For that one plan the projected benefit obligation and accumulated benefit obligation were $67 million and $62 million, respectively, as of December 31, 1999, and $55 million and $45 million, respectively, as of December 31, 1998. 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 The company offers 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 one percent to 15 percent of their regular earnings. Employer contributions, after one year of completed service, are made in shares of company 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. The employees' 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 employee stock ownership plan referred to below. Contributions to the savings plans were $14 million in 1999, $14 million in 1998 and $11 million in 1997. The fair value of company stock held by the savings plan was $391 million at December 31, 1999, and $566 million at December 31, 1998. EMPLOYEE STOCK OWNERSHIP PLAN (ESOP) All contributions to the Employee Stock Ownership Plan and Trust (Trust) are made by the company; 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 2.9 million and 3.1 million shares of Sempra Energy common stock, with fair values of $51.1 million and $77.9 million, at December 31, 1999, and 1998, 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 nonqualified 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 1999 and 1998, 85,400 shares and 102,640 shares, respectively, of restricted company stock were awarded to officers. In 1997, Enova awarded 75,000 shares to key executives. Each award is subject to forfeiture after 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 company stock. Compensation expense for the issuance of these restricted shares was approximately $1 million in 1999, $2 million in 1998 and $1 million in 1997. In 1999 and 1998, Sempra Energy granted 3,372,400 stock options and 3,425,800 stock options, respectively. 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 dividend equivalents. 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 originally were scheduled to vest annually over a service period ranging from three to five years. Compensation expense (or reduction thereof) for the stock option grants was ($13 million), $12 million and $17 million in 1999, 1998 and 1997, respectively. Had compensation cost for the stock-based compensation plans been determined based on the fair value at the grant dates for awards under those plans, consistent with the method of FASB Statement 123, the company's net income (earnings per share) would have been $378 million ($1.59 per share), $285 million ($1.20 per share) and $439 million ($1.85 per share) for 1999, 1998 and 1997, respectively. The plans permit the granting of dividend equivalents, which provide grantees the opportunity to receive some or all of the cash dividends that would have been paid on the shares since the grant date, depending on the degree, if any, by which certain corporate goals are met. For grants prior to July 1, 1998, payment of the dividend equivalents is also contingent upon exercise of the options and requires that the market value of the shares purchased exceeds the option price. 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 DIVIDEND EQUIVALENTS Shares Average Options Under Exercise Exercisable Option Price at Year End
- ------------------------------------------------------------------------------- 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 Granted 1,451,100 21.00 Exercised (254,886) 17.32 Cancelled (99,677) 23.34 ------------------------------------ December 31, 1999 4,693,197 $21.96 1,844,079 - -------------------------------------------------------------------------------
- ------------------------------------------------------------------------------- OPTIONS WITHOUT DIVIDEND EQUIVALENTS Shares Average Options Under Exercise Exercisable Option Price at Year End
- ------------------------------------------------------------------------------- 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 Granted 1,921,300 21.00 Exercised (12,781) 15.20 Cancelled (55,746) 23.25 ------------------------------------ December 31, 1999 3,673,005 $22.43 809,056 - -------------------------------------------------------------------------------
Additional information on options outstanding at December 31, 1999, is as follows: - ------------------------------------------------------------------------------- OUTSTANDING OPTIONS Number Average Average Range of of Remaining Exercise Exercise Prices Shares Life Price
- ------------------------------------------------------------------------------- $12.80-$16.12 502,164 4.44 $15.15 $16.79-$21.00 4,733,585 8.52 $20.45 $24.10-$31.00 3,130,453 8.06 $25.82 ---------- 8,366,202 8.10 $22.14 - -------------------------------------------------------------------------------
- ------------------------------------------------------------------------------- Exercisable Options Number Average Range of of Exercise Exercise Prices Shares Price
- ------------------------------------------------------------------------------- $12.80-$16.12 502,164 $15.15 $16.79-$20.36 1,168,825 $18.89 $24.11-$31.00 982,146 $25.84 --------- 2,653,135 $20.75 - -------------------------------------------------------------------------------
The fair value of each option grant (including dividend equivalents where applicable) was estimated on the date of grant using the modified Black-Scholes option-pricing model. Weighted average fair values for options granted in 1999, 1998 and 1997 were $4.24, $8.20 and $5.23, respectively. The assumptions that were used to determine these fair values are as follows: - ------------------------------------------------------------------------------- 1999 1998 1997
- ------------------------------------------------------------------------------- Stock price volatility 19% 16% 18% Risk-free rate of return 5.5% 5.6% 6.4% Annual dividend yield 0%/6.11% 0%/5.27% 0% Expected life 6 Years 6 Years 3.8 Years - -------------------------------------------------------------------------------
The second yield percentages apply to the options that do not include dividend equivalents. 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-term 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 $3.0 billion, respectively, at December 31, 1999, and $3.1 billion and $3.2 billion, respectively, at December 31, 1998. Included in long-term debt are SDG&E's rate-reduction bonds. The carrying amounts and fair values of the bonds are $526 million and $511 million, respectively, at December 31, 1999, and $592 million and $607 million, respectively, at December 31, 1998. The carrying amounts and fair values of subsidiaries' preferred stock are $204 million and $167 million, respectively, at December 31, 1999, and $204 million and $182 million, respectively, at December 31, 1998. 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. 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- rate 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, 1999, and 1998, 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 $1.3 million at December 31, 1999 ($3 million at December 31, 1998). Additional information on this topic is included in Note 5. ENERGY DERIVATIVES Information on derivative financial instruments of SET is provided below. The company uses energy derivatives for 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, 1999, 1998 and 1997, gains and losses from natural gas futures contracts are not material to the company's 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 other market makers as well as end users. 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, 1999, 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 also is affected by changes in volatility and liquidity in markets in which these instruments are traded. SET adjusts these derivatives to market each month with gains and losses recognized in earnings. These instruments are included in the Consolidated Balance Sheets as energy trading assets or liabilities. 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 revenue or expense, whichever is appropriate, in the Consolidated Income Statements. Sempra Energy guarantees many of SET's transactions. 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, 1999, 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 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 $ 24 $ 2 $ 26 AA 44 5 49 A 262 49 311 BBB 144 13 157 Below investment grade 84 32 116 Exchanges 37 1 38 -------------------------------- $595 $102 $697 - -------------------------------------------------------------------------------
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 1999 and 1998, based on quarterly observation, for trading assets and trading liabilities which are considered financial instruments with off- balance-sheet risk, approximate $1,229 million and $1,033 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, 1999, and 1998, SET's energy trading assets and trading liabilities approximate the following: - ------------------------------------------------------------------------------- December 31 (Dollars in millions) 1999 1998
- ------------------------------------------------------------------------------- ENERGY TRADING ASSETS Unrealized gains on swaps and forwards $1,244 $756 Due from commodity clearing organization and clearing brokers 124 75 OTC commodity options purchased 108 45 Due from trading counterparties 63 30 --------------- Total $1,539 $906 - ------------------------------------------------------------------------------- ENERGY TRADING LIABILITIES Unrealized losses on swaps and forwards $1,210 $740 Due to trading counterparties 82 35 OTC commodity options written 73 30 ---------------- Total $1,365 $805 - -------------------------------------------------------------------------------
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. At December 31, 1999, the notional amounts of SET's financial instruments are: - ------------------------------------------------------------ (Dollars in millions) Total
- ------------------------------------------------------------ Forwards and commodity swaps $20,044 Futures and exchange options 1,021 Options purchased 1,790 Options written 1,784 ------- Total $24,639 - ------------------------------------------------------------
11 PREFERRED STOCK OF SUBSIDIARIES - ------------------------------------------------------------------------------- PACIFIC ENTERPRISES December 31 Call (Dollars in millions except call price) Price 1999 1998
- ------------------------------------------------------------------------------- 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 part of every series 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 Class A preferred stock are outstanding. - ------------------------------------------------------------------------------- SOCALGAS December 31 (Dollars in millions) 1999 1998
- ------------------------------------------------------------------------------- Not subject to mandatory redemption: $25 par value, authorized 1,000,000 shares 6% Series, 28,134 and 28,664 shares outstanding at December 31, 1999 and 1998 $ 1 $ 1 6% Series A, 783,032 shares outstanding 19 19 Without par value, authorized 10,000,000 shares 7.75% Series - - -------------- $20 $20 - -------------------------------------------------------------------------------
None of SoCalGas' series of preferred stock is callable. All series have one vote per share and cumulative preferences as to dividends. - ------------------------------------------------------------------------------- SDG&E December 31 Call (Dollars in millions except call price) Price 1999 1998
- ------------------------------------------------------------------------------- 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 type of potential common stock at December 31, 1999, 1998 and 1997. The reconciliation between basic and diluted EPS is as follows: - ------------------------------------------------------------------------------- Income Shares Earnings (in millions) (in thousands) Per Share
- ------------------------------------------------------------------------------- 1999: Basic $394 237,245 $1.66 Effect of dilutive stock options 308 ------------------------------------- Diluted $394 237,553 $1.66 - ------------------------------------------------------------------------------- 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 - -------------------------------------------------------------------------------
This calculation excludes options covering 3.3 million shares for 1999 and 1998, and 0.2 million shares for 1997 for which the exercise price was greater than the shares' market price. The company is authorized to issue 750,000,000 shares of no-par- value common stock and 50,000,000 shares of Preferred Stock. Excluding shares held by the ESOP, there were 237,408,051 shares of common stock outstanding at December 31, 1999, compared to 236,956,683 shares at December 31, 1998. 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 primarily from various Southwest U.S. suppliers and are based on monthly spot-market prices. SoCalGas has contracts with pipeline companies. These contracts expire at various dates through the year 2006. In 1998, SoCalGas restructured its long-term commodity purchase contracts with suppliers of California offshore and Canadian gas. These new purchase contracts expire at the end of 2003. SDG&E has long-term capacity contracts with interstate pipelines which expire on various dates between 2007 and 2023. These agreements provide for payments of an annual reservation charge. SoCalGas and SDG&E recover such fixed charges in rates. SDG&E had been involved in negotiations and litigation with four Canadian suppliers concerning contract terms and prices related to long-term natural gas supply contracts. In 1999, SDG&E settled with the last of the four suppliers, terminating the contract. SDG&E continues to purchase natural gas from one of the suppliers under terms of the settlement agreement. SDG&E purchases natural gas on a spot basis to fill any additional long-term pipeline capacity. SDG&E intends to continue using the long-term pipeline capacity in other ways as well, including the transport of replacement natural gas and the release of a portion of this capacity to third parties. In connection with the new natural gas franchise for Nova Scotia, the company plans to build and operate a natural gas system providing service to 78 percent of the 350,000 households in Nova Scotia. Construction of the system is expected to begin in mid-2000. See Note 3 for additional information. At December 31, 1999, the future minimum payments under natural gas contracts were: - ------------------------------------------------------------------------ Storage and Natural (Dollars in millions) Transportation Gas
- ------------------------------------------------------------------------ 2000 $ 191 $425 2001 193 188 2002 195 194 2003 197 172 2004 197 - Thereafter 511 - ------------------- Total minimum payments $1,484 $979 - ------------------------------------------------------------------------
Total payments under the contracts were $1.3 billion in 1999 and 1998, and $1.4 billion in 1997. 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 2001. 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 2000 and 2025. Under California's electric-industry restructuring law, which is described in Note 14, the above-market cost of these contracts is recovered from virtually all of SDG&E's customers. In general, the market value of these contracts is recovered by bidding them into the California Power Exchange (PX) and receiving revenue from the PX for bids accepted. At December 31, 1999, the estimated future minimum payments under the long-term contracts were: - ----------------------------------------------------------------- (Dollars in millions)
- ----------------------------------------------------------------- 2000 $ 198 2001 180 2002 133 2003 133 2004 127 Thereafter 2,046 ------ Total minimum payments $2,817 - -----------------------------------------------------------------
The payments represent capacity charges and minimum energy purchases. SDG&E is required to pay additional amounts for actual purchases of energy that exceed the minimum energy commitments. Total payments under the contracts were $251 million in 1999, $293 million in 1998 and $421 million in 1997. LEASES The company has leases (primarily operating) on real and personal property expiring at various dates from 2000 to 2037. 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 and real property that are financed by long-term capital leases. Property, plant and equipment includes $83 million at December 31, 1999, and $214 million at December 31, 1998, related to these leases. The associated accumulated amortization is $39 million and $127 million, respectively. The minimum rental commitments payable in future years under all noncancellable leases are: - ------------------------------------------------------------------------ Operating Capitalized (Dollars in millions) Leases Leases
- ------------------------------------------------------------------------ 2000 $ 66 $ 29 2001 63 6 2002 65 6 2003 57 3 2004 51 2 Thereafter 335 4 ---------------------- Total future rental commitment $637 50 Imputed interest (5% to 15%) (7) --- Net commitment $ 43 - ------------------------------------------------------------------------
Rent expense totaled $108 million in 1999, $105 million in 1998 and $137 million in 1997. 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 $70 million at December 31, 1999. These leases are reflected in the above table. OTHER COMMITMENTS AND CONTINGENCIES At December 31, 1999, commitments for capital expenditures, including the purchase of gas turbines, were approximately $87 million. ENVIRONMENTAL ISSUES The company's operations are subject to federal, state and local environmental laws and regulations governing hazardous wastes, air and water quality, land use, solid waste disposal and the protection of wildlife. Significant costs are incurred to operate the facilities in compliance with these laws and regulations and these costs 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 $1.5 million in 1999, $1 million in 1998 and $5 million in 1997, and are not expected to be significant during the next five years due to the sale of SDG&E's fossil fuel power plants. 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. As discussed in Note 14, restructuring of the California electric- utility industry has changed the way utility rates are set and costs are recovered. In 1998, the CPUC modified the Hazardous Waste Collaborative mechanism by providing that electric generation- related cleanup costs be eligible for transition-cost recovery. The effect of this decision is that SDG&E's costs of compliance with environmental regulations may not be fully recoverable. NUCLEAR INSURANCE SDG&E and the co-owners of SONGS have purchased primary insurance of $200 million, the maximum amount available, for public-liability claims. An additional $9.5 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 $36 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 12 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 $5 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. The Nuclear Waste Policy Act of 1982 made the DOE responsible for the disposal of nuclear fuel and other radioactive waste. However, it is uncertain when the DOE will begin accepting nuclear fuel from SONGS. Continued delays by the DOE can lead to increased cost of disposal, which could be significant. If this occurs and the company is unable to recover the increased costs from the federal government or from its customers, the company's profitability from SONGS would be adversely affected. 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, 1999, the aggregate unexpended amount of this commitment was approximately $105 million. Capital expenditures for underground conversions were $20 million in 1999, and $17 million in 1998 and 1997. CONCENTRATION OF CREDIT RISK The company maintains credit policies and systems to minimize overall credit risk. These policies include, when applicable, 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 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 PX that serves as an independent 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. California's investor- owned 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. Purchases from the PX/ISO are included in purchased-power expenses and PX/ISO power revenues have been netted therein on the Statements of Consolidated Income. Revenues from the PX/ISO reflect sales to the PX/ISO commencing April 1, 1998, at market prices of energy from SDG&E's power plants and from long-term purchased-power contracts. 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 the utilities had 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. Outside of those exceptions, any stranded costs not recovered through 2001 would 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 6. In June 1999, SDG&E completed the recovery of its stranded costs, other than the future above-market portion of qualifying facilities and other purchased-power contracts that were in effect at December 31, 1995, and SONGS costs as described below, both of which will continue to be collected in rates. Recovery of the other stranded costs was affected by, among other things, the sale of SDG&E's fossil power plants and combustion turbines during the quarter ended June 30, 1999. The South Bay Power Plant sale to the San Diego Unified Port District for $110 million was completed on April 23, 1999. Duke South Bay, a subsidiary of Duke Energy Power Services, will manage the plant for the Port District. The sale of the Encina Power Plant and 17 combustion-turbine generators to Dynegy Inc. and NRG Energy Inc. for $356 million was completed on May 21, 1999. SDG&E will operate and maintain both the South Bay and Encina facilities for the new owners until April 2001 and May 2001, respectively. Stranded costs included the cost of SONGS as of December 31, 1995. SDG&E retains ownership of its 20-percent interest in SONGS. Subsequent SONGS costs are recoverable only from the sales of power produced from SONGS, at rates previously fixed by the CPUC through December 31, 2003, and as determined by the market thereafter. If approved by the CPUC, SDG&E is planning to auction its interest in SONGS. A major issue being addressed is how to handle the decommissioning trust to ensure that adequate funding is available at the time the plant is decommissioned. AB 1890 required a 10-percent reduction of residential and small- commercial customers' rates, beginning in January 1998, and provided for the issuance of rate-reduction bonds by an agency of the state of California to enable the IOUs to achieve this rate reduction. In December 1997, $658 million of rate-reduction bonds were issued on behalf of SDG&E at an average interest rate of 6.26 percent. These bonds are being repaid over 10 years by SDG&E's residential and small commercial customers via a nonbypassable charge on their electric bills. In 1997, SDG&E formed a subsidiary, SDG&E Funding LLC, to facilitate the issuance of the bonds. In exchange for the bond proceeds, SDG&E sold to SDG&E Funding LLC all of its rights to certain revenue streams collected from such customers. Consequently, the transaction is structured to cause such revenue streams not to be the property of SDG&E nor to be available to satisfy any claims of SDG&E's creditors. The sizes of the rate-reduction bond issuances were set so as to make the IOUs neutral as to the 10-percent rate reduction, and were based on a four-year period to recover stranded costs. Because SDG&E recovered its stranded costs in only 18 months (due to the greater- than-anticipated plant-sale proceeds), the bond proceeds were greater than needed. Accordingly, SDG&E will return to its customers over $400 million that it has collected or will collect from its customers. The timing of the return will differ from the timing of the collection, but the specific timing of the repayment and the interest rate thereon are the subject of a CPUC proceeding and are expected to be resolved in early 2000. This refund will not affect SDG&E's net income, except to the extent that the interest associated with the refund (12.63 percent if not reduced as a result of the CPUC proceeding) differs from the return earned by the company on the funds to be refunded. The bonds and their repayment schedule are unaffected by this refund. AB 1890 also includes a rate freeze for all IOU customers. Beginning in 1998, SDG&E's system-average rates were fixed at 9.43 cents per kwh. The rate freeze would have stayed in place until January 1, 2002. However, in connection with completion of its stranded cost recovery (described above), SDG&E filed with the CPUC for a mechanism to structure electric rates after the end of the rate freeze. SDG&E received approval to reduce base rates (the non- commodity portion of rates) to all electric customers effective July 1, 1999. As a result base electric rates will decrease beyond the original 10-percent rate reduction described above. The portion of the electric rate representing the commodity cost is simply passed through to customers and will fluctuate with the price of electricity from the PX. Except for the interim protection mechanism described below, customers will no longer be insulated from commodity price fluctuations. In April 1999, SDG&E filed an all-party settlement (including energy service providers, the CPUC's Office of Ratepayer Advocates and the Utility Consumers Action Network) detailing proposed implementation plans for lifting the rate freeze. Included in the settlement is an interim customer-protection mechanism for residential and small- commercial customers that capped rates between July 1999 and September 1999, regardless of how high the PX price had moved during that period. The resulting undercollection (which amounted to less than $1 million) is being recovered through a balancing-account mechanism. A CPUC decision adopting the all-party settlement was issued in May 1999 and became effective July 1, 1999. The interim post-rate-freeze period runs until the CPUC issues its decision on the pending legal and policy issues of ending the rate freeze. This decision is expected during the second quarter of 2000. The decision will address, among other things, a proposal by SDG&E that would limit SDG&E's obligation to purchase from the PX to 80 percent of the electricity required by its utility default customers, and to establish an electric commodity performance-based regulation mechanism, which would measure the company's effectiveness in procuring electricity on behalf of its utility default commodity customers and the administration of its above-market purchased-power contracts. 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 in rates. 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 restructuring has been confined to generation. Transmission and distribution have remained subject to traditional cost-of-service regulation and performance-based ratemaking. However, the CPUC is exploring the possibility of opening up electric distribution to competition. During 2000, the CPUC will consider whether any changes should be made in electric distribution regulation. A CPUC staff report will be submitted on this issue to the CPUC in the second quarter of 2000. SDG&E and SoCalGas will actively participate in this effort. On December 20, 1999, the FERC issued "Order 2000" concerning the formation of Regional Transmission Organizations (RTOs). The rule generally requires all public utilities that own, operate or control interstate transmission to file by October 15, 2000, a proposal for an RTO. Public utilities that are members of an existing, FERC- approved regional entity, which includes SDG&E, must file by January 15, 2001. The rule states that RTOs will be operational by December 15, 2001. The FERC's order permits a number of different types of RTOs, including nonprofit independent system operators, for-profit transmission companies, or other approaches. The FERC also allows flexibility so that an RTO can improve its structure, geographic scope, market support and operations to meet market needs. It notes that the FERC intends for RTOs to alleviate stress on the bulk power system caused by changes in the structure of the industry; improve efficiencies in transmission grid management through better pricing and congestion management; improve grid reliability; remove remaining opportunities for discriminatory transmission practices; improve market performance; increase coordination among state regulatory agencies; cut transaction costs; facilitate the success of state retail access programs; and facilitate reduced regulation. The order also specifies the required characteristics for each RTO, including independence from market participants, and the functional responsibilities required of each RTO. The order also provides guidance on transmission pricing reforms. The identification of RTO regions and formation of the RTOs will be subject to a collaborative process. The impact of Order 2000 on SDG&E depends on the results of this process and other implementation issues. 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's natural gas consumers. In August 1998, California enacted a law prohibiting the CPUC from enacting any natural gas-industry restructuring decision for core (residential and small-commercial) customers prior to January 1, 2000. During the implementation moratorium, the CPUC held hearings throughout the state and intends to give the legislature a draft ruling before adopting a final market-structure policy. SDG&E and SoCalGas have been actively participating in this effort and have argued in support of competition intended to maximize benefits to customers rather than to protect competitors. In October 1999, the state of California enacted a law (AB 1421) which requires that gas utilities provide "bundled basic gas service" (including transmission, storage, distribution, purchasing, revenue-cycle services and after-meter services) to all core customers, unless the customer chooses to purchase gas from a nonutility provider. The law prohibits the CPUC from further unbundling of distribution-related gas services (including meter reading and billing) and after-meter services (including leak investigation, inspecting customer piping and appliances, pilot relighting and carbon monoxide investigation) for most customers. The objective is to preserve both customer safety and customer choice. 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 plant in a market where a utility already has a highly developed infrastructure. The utilities' PBR mechanisms are in effect through December 31, 2002; however, the CPUC decision allows for the possibility that changes to SoCalGas' mechanism could be adopted in its 1999 Biennial Cost Allocation Proceeding decision, which is anticipated during the second quarter of 2000. Each company's PBR mechanism is scheduled to be updated at December 31, 2002, at which time it will be updated for, among other things, changes in costs and volumes. Key elements of the mechanisms 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 or awards if service quality exceeds set standards. Specifically, the key elements of the mechanisms 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, SDG&E and SoCalGas were authorized to earn 9.05 percent and 9.49 percent returns, respectively, on their rate base. For 2000, their authorized returns are 8.75 percent for SDG&E and 9.49 percent for SoCalGas. *Base rates are indexed based on inflation less an estimated productivity factor. *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 related to employee safety, electric reliability, customer satisfaction, and call-center responsiveness. The SoCalGas mechanism authorizes penalties of up to $4 million annually, or more in certain, limited situations. *The SoCalGas mechanism 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. *Annual cost of capital proceedings are replaced by an automatic adjustment mechanism if changes in certain indices exceed established tolerances. The SoCalGas 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. The SDG&E mechanism is triggered by a 6-month trailing average and a 100-basis-point change in interest rates. If this occurs, there would be an automatic adjustment of rates for the change in the cost of capital according to a formula which applies a percentage of the change to various capital components. 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 permitted 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 revenues were governed by the Comprehensive Settlement through July 31, 1999. This treatment is being replaced by the PBR mechanism as adopted in the 1999 Biennial Cost Allocation Proceeding (BCAP). The CPUC's proposed decision on the 1999 BCAP would allow balancing account treatment for 75 percent of noncore revenues. *The Gas Cost Incentive Mechanism (GCIM) for evaluating SoCalGas' natural gas purchases substantially replaced the previous process of reasonableness reviews. In December 1998 the CPUC extended the GCIM program indefinitely. 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 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 1998 the CPUC approved GCIM-related shareholder awards to SoCalGas totalling $13 million. In June 1999, SoCalGas filed its annual GCIM application with the CPUC requesting an award of $8 million for the annual period ended March 31, 1999. A CPUC decision is expected during the first quarter of 2000. 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 further charges 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 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, FERC is reviewing the decision. On November 4, 1999, the CPUC issued a decision on the 1996 BCAP, shifting $88 million of pipeline surcharges from the pipeline capacity relinquishments to noncore customers. The noncore customer rate impact of the decision is mitigated by overcollections in the regulatory accounts and will be reflected in the rates adopted in the final 1999 BCAP 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 SoCalGas' Comprehensive Settlement (discussed above), and the proposed end date aligns with the expiration of the utilities' current PBRs. On January 11, 2000, the CPUC issued a proposed decision adopting overall decreases in natural gas revenues of $208 million for SoCalGas and $38 million for SDG&E. A final CPUC decision is expected in the second quarter of 2000. COST OF CAPITAL For 2000, 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 1999, 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 has changed the method of calculating the utility's annual cost of capital. In June 1999, the CPUC adopted a 10.6 percent ROE and an 8.75 percent ROR for SDG&E's electric- distribution and natural gas businesses. The electric-transmission cost of capital is determined under a separate FERC proceeding. 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 nondiscrimination, 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, which is described in Note 1. 15 SEGMENT INFORMATION The company, primarily an energy services company, has three separately managed reportable segments comprised of SoCalGas, SDG&E and SET. The two utilities operate in essentially separate service territories under separate regulatory frameworks and rate structures set by the CPUC. 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, Conn., and is engaged in wholesale trading and marketing of natural gas, power and petroleum in the United States and Europe. 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 years ended December 31 (Dollars in millions) 1999 1998 1997
- ------------------------------------------------------------------------------- OPERATING REVENUES: Southern California Gas $2,569 $2,427 $2,641 San Diego Gas & Electric 2,207 2,249 2,167 Sempra Energy Trading 450 110 - Intersegment revenues (72) (59) (55) All other 206 254 316 ------------------------- Total $5,360 $4,981 $5,069 ------------------------- INTEREST REVENUE: Southern California Gas $ 16 $ 4 $ 1 San Diego Gas & Electric 40 31 4 Sempra Energy Trading 3 3 - All other interest (26) 2 29 ------------------------- Total interest 33 40 34 Sundry income (loss) 42 (6) 12 ------------------------- Total other income $ 75 $ 34 $ 46 ------------------------- DEPRECIATION AND AMORTIZATION: Southern California Gas $ 260 $ 254 $ 251 San Diego Gas & Electric (See Note 14) 561 603 324 Sempra Energy Trading 23 13 - All other 35 59 29 ------------------------- Total $ 879 $ 929 $ 604 ------------------------- INTEREST EXPENSE: Southern California Gas $ 60 $ 80 $ 87 San Diego Gas & Electric 120 106 74 Sempra Energy Trading 15 5 - All other 34 6 33 ------------------------ Total $ 229 $ 197 $ 194 ------------------------ INCOME TAX EXPENSE (BENEFIT): Southern California Gas $ 182 $ 128 $ 178 San Diego Gas & Electric 126 142 219 Sempra Energy Trading (7) (9) - All other (122) (123) (96) ------------------------- Total $ 179 $ 138 $ 301 ------------------------- NET INCOME: Southern California Gas $ 200 $ 158 $ 231 San Diego Gas & Electric 193 185 232 Sempra Energy Trading 19 (13) - All other (18) (36) (31) ------------------------- Total $ 394 $ 294 $ 432 -------------------------
- ------------------------------------------------------------------------------- At December 31, or for the years then ended (Dollars in millions) 1999 1998 1997
- ------------------------------------------------------------------------------- ASSETS: Southern California Gas $ 3,532 $ 3,834 $ 4,205 San Diego Gas & Electric 4,366 4,257 4,654 Sempra Energy Trading 1,829 1,225 846 All other 1,543 1,140 1,051 ---------------------------- Total $11,270 $10,456 $10,756 ---------------------------- CAPITAL EXPENDITURES: Southern California Gas $ 146 $ 128 $ 159 San Diego Gas & Electric 245 227 197 Sempra Energy Trading 26 - - All other 172 83 41 ---------------------------- Total $ 589 $ 438 $ 397 ---------------------------- GEOGRAPHIC INFORMATION: Long-lived assets: United States $ 5,857 $ 5,849 $ 5,904 Latin America 701 140 67 ---------------------------- Total $ 6,558 $ 5,989 $ 5,971 ---------------------------- OPERATING REVENUES: United States $ 5,280 $4,974 $ 5,058 Latin America 16 7 11 Europe 62 - - Canada 2 - - ---------------------------- Total $ 5,360 $ 4,981 $ 5,069 - -------------------------------------------------------------------------------
16 SEMPRA ENERGY HOLDINGS On May 5, 1999, Sempra Energy and its wholly owned subsidiary, Sempra Energy Holdings (SEH), jointly filed a shelf registration for the public offering of common stock, preferred stock and debt securities of Sempra Energy; debt securities of SEH; and certain other securities to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933. Any debt securities issued by SEH would be fully guaranteed by Sempra Energy. At December 31, 1999, no debt securities were outstanding. Summarized financial information of SEH is provided below. - ------------------------------------------------------------------------------- December 31 (Dollars in millions) 1999 1998
- ------------------------------------------------------------------------------- Current assets $2,271 $1,470 Noncurrent assets 1,317 544 Current liabilities 2,124 1,452 Noncurrent liabilities 502 140 - -------------------------------------------------------------------------------
- ------------------------------------------------------------------------------- For the Years ended December 31 (Dollars in millions) 1999 1998 1997
- ------------------------------------------------------------------------------- Operating revenues $672 $572 $526 Other income 63 14 - Operating expenses 682 667 585 Net income (loss) 11 (54) (17) - -------------------------------------------------------------------------------
17 SUBSEQUENT EVENT On January 26, 2000, the company announced a tender offer to purchase up to 36 million shares, or approximately 15 percent, of outstanding common shares, and a reduction in its quarterly dividend payable on shares of its common stock to $0.25 per share ($1.00 annualized rate) from its previous level of $0.39 per share ($1.56 annualized rate) commencing with the dividend payable in the second quarter of 2000. On February 23, 2000, the company completed the sale of $500 million of long-term notes and $200 million of mandatorily redeemable trust preferred securities to finance substantially all of the tender offer. On February 25, 2000, the tender offer was completed, with all 36 million shares sought being tendered. QUARTERLY FINANCIAL DATA (UNAUDITED) Quarter ended (Dollars in millions except per-share amounts) March 31 June 30 September 30 December 31
- ---------------------------------------------------------------------------------------------- 1999 Revenues and other income $1,191 $1,517 $1,254 $1,473 Operating expenses 971 1,380 1,006 1,276 --------------------------------------------------- Operating income $ 220 $ 137 $ 248 $ 197 --------------------------------------------------- Net income $ 99 $ 82 $ 108 $ 105 Average common shares outstanding (diluted) 237.4 237.5 237.8 237.6 Net income per common share (diluted) $ .42 $ .35 $ .45 $ .44 1998 Revenues and other income $1,348 $1,219 $1,143 $1,305 Operating expenses 1,164 1,135 940 1,147 --------------------------------------------------- Operating income $ 184 $ 84 $ 203 $ 158 --------------------------------------------------- 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 - ----------------------------------------------------------------------------------------------
QUARTERLY COMMON STOCK DATA (UNAUDITED) 1999 1998 - ---------------------------------------------------------------------------------------------- First Second Third Fourth First Second Third Fourth Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
- ---------------------------------------------------------------------------------------------- Market price High $26 $24 7/8 $23 3/16 $21 3/4 * * $28 7/8 $29 5/16 Low 19 1/8 18 1/2 20 7/16 17 1/8 * * 23 3/4 24 9/16 Dividends declared(1) $0.39 $0.39 $0.39 $0.39 $0.32 $0.46 $0.39 $0.39 - ----------------------------------------------------------------------------------------------
*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. EX-21 4 SCHEDULE OF SIGNIFICANT SUBSIDIARIES EXHIBIT 21.01 SEMPRA ENERGY Schedule of Significant Subsidiaries at December 31, 1999 State of Incorporation Subsidiary or Other Jurisdiction - ---------- ---------------------- Chilquinta Energia, S.A. Chile Luz del Sur, S.A. Peru San Diego Gas & Electric Company California Sempra Energy Financial California Sempra Energy Holdings California Sempra Energy International California Sempra Energy Resources California Sempra Energy Services Texas Sempra Energy Trading Corp. Delaware Southern California Gas Company California EX-27 5 FINANCIAL DATA SCHEDULE
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE STATEMENT OF CONSOLIDATED INCOME, BALANCE SHEET, AND CASH FLOWS AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 0001032208 SEMPRA ENERGY 1,000,000 YEAR DEC-31-1999 DEC-31-1999 PER-BOOK 4,992 2,117 3,040 863 258 11,270 1,966 0 1,101 2,986 25 179 2,859 0 0 182 155 0 43 0 4,841 11,270 5,360 179 4,633 4,812 548 75 623 229 394 0 394 368 139 1,188 1.66 1.66 PREFERRED DIVIDEND OF SUBSIDIARY INCLUDED IN OTHER OPERATING EXPENSE
-----END PRIVACY-ENHANCED MESSAGE-----