-----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, T6iiWyk9dSi2yt0BQoAAAkqJ8dVnNQXzppaCOG3NX1/hdKoJonVdKAn9ZzeagrEs jx+3/KoWRE4RknsD6SjbFA== 0000086521-03-000007.txt : 20030226 0000086521-03-000007.hdr.sgml : 20030226 20030226172429 ACCESSION NUMBER: 0000086521-03-000007 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 20021231 FILED AS OF DATE: 20030226 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PACIFIC ENTERPRISES INC CENTRAL INDEX KEY: 0000075527 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS DISTRIBUTION [4924] IRS NUMBER: 940743670 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-00040 FILM NUMBER: 03581606 BUSINESS ADDRESS: STREET 1: 555 WEST 5TH ST STREET 2: STE 2900 CITY: LOS ANGELES STATE: CA ZIP: 90013 BUSINESS PHONE: 2138955000 MAIL ADDRESS: STREET 1: 555 WEST 5TH STREET STREET 2: SUITE 2900 CITY: LOS ANGELES STATE: CA ZIP: 90013 FORMER COMPANY: FORMER CONFORMED NAME: PACIFIC LIGHTING CORP DATE OF NAME CHANGE: 19880224 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHERN CALIFORNIA GAS CO CENTRAL INDEX KEY: 0000092108 STANDARD INDUSTRIAL CLASSIFICATION: NATURAL GAS TRANSMISSION [4922] IRS NUMBER: 951240705 STATE OF INCORPORATION: CA FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-01402 FILM NUMBER: 03581607 BUSINESS ADDRESS: STREET 1: 555 W FIFTH ST STREET 2: ML 14H1 CITY: LOS ANGELES STATE: CA ZIP: 90013-1011 BUSINESS PHONE: 2132441200 MAIL ADDRESS: STREET 1: 555 WEST 5TH STREET CITY: LOS ANGELES STATE: CA ZIP: 90051-1011 10-K 1 pe_scg10k2002.txt 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, 2002 OR [ ] Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the transition period from to . Exact Name of Commission Registrant IRS Employer File as specified State of Identification Number in its charter Incorporation Number - ---------- -------------- -------------- ------------- 1-40 PACIFIC ENTERPRISES California 94-0743670 1-1402 SOUTHERN CALIFORNIA GAS COMPANY California 95-1240705 555 WEST FIFTH STREET, LOS ANGELES, CALIFORNIA 90013 - ---------------------------------------------- ---------- (Address of principal executive offices) (Zip Code) Registrant's telephone number, including area code (213)244-1200 -------------- SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: Name of each exchange Title of each class on which registered - ------------------- --------------------- Pacific Enterprises Preferred Stock: American and Pacific $4.75 dividend; $4.50 dividend; $4.40 dividend; $4.36 dividend Southern California Gas Co. Preferred Stock Pacific Southern California Gas Co. First Mortgage Bonds: New York Series BB, due 2023; Series DD, due 2023; Series EE, due 2025; Series FF, due 2003 SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Pacific Enterprises None Southern California Gas Company 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. [ X ] Exhibit Index on page 80. Glossary on page 83. Aggregate market value of the voting stock held by non-affiliates of the registrant as of January 31, 2003: Pacific Enterprises $57.8 Million Southern California Gas Company $16.7 Million Common Stock outstanding without par value as of January 31, 2003: Pacific Enterprises Wholly owned by Sempra Energy Southern California Gas Company Wholly owned by Pacific Enterprises DOCUMENTS INCORPORATED BY REFERENCE: Portions of the Information Statement prepared for the May 2003 annual meeting of shareholders are incorporated by reference into Part III. 1 TABLE OF CONTENTS PART I Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 3 Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 12 Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . 12 Item 4. Submission of Matters to a Vote of Security Holders. . 12 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters . . . . . . . . . . . . . . . . 12 Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 13 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . . 13 Item 7A. Quantitative and Qualitative Disclosures About Market Risk . . . . . . . . . . . . . . . . . 26 Item 8. Financial Statements and Supplementary Data. . . . . . 27 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure . . . . . . . . 71 PART III Item 10. Directors and Executive Officers of the Registrant . . 71 Item 11. Executive Compensation . . . . . . . . . . . . . . . . 72 Item 12. Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . . . 72 Item 13. Certain Relationships and Related Transactions . . . . 72 Item 14 Controls and Procedures. . . . . . . . . . . . . . . . 72 PART IV Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K . . . . . . . . . . . . . . . . . . . . 73 Independent Auditors' Consent and Report on Schedule. . . . . . 75 Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 78 Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 80 Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 83 Certifications. . . . . . . . . . . . . . . . . . . . . . . . . 85 2 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," "would" and "should" or similar expressions, or discussions of strategy or of plans are intended to identify forward-looking statements. Forward- looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future results may differ materially from those expressed in these forward-looking statements. Forward-looking 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, legislative and regulatory conditions and developments; actions by the California Public Utilities Commission (CPUC), the California Legislature, and the Federal Energy Regulatory Commission (FERC); capital market conditions, inflation rates, interest rates and exchange rates; energy and trading markets, including the timing and extent of changes in commodity prices; weather conditions and conservation efforts; war and terrorist attacks; business, regulatory and 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 companies. 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 companies' business described in this report and other reports filed by the companies from time to time with the Securities and Exchange Commission. PART I ITEM 1. BUSINESS Description of Business Pacific Enterprises (PE or the company) is an energy services company whose only direct subsidiary is Southern California Gas Company (SoCalGas), the nation's largest natural gas distribution utility. PE's common stock is wholly owned by Sempra Energy, a California-based Fortune 500 holding company, and PE owns all of the common stock of SoCalGas. The financial statements herein are, in one case, the Consolidated Financial Statements of PE and its subsidiary, SoCalGas, and, in the second case, the Consolidated Financial Statements of SoCalGas and its subsidiaries, which comprise less than one percent of SoCalGas' consolidated financial position and results of operations. Sempra Energy also indirectly owns all of the common stock of San Diego Gas & Electric (SDG&E). SoCalGas and SDG&E are collectively referred to herein as "the California Utilities." A description of PE and SoCalGas is given in "Management's Discussion and Analysis of Financial Condition and Results of Operations" herein. As PE itself has no operations, PE's financial position and operations consist of those of SoCalGas and some additional items attributable to PE's position as a holding company (e.g. cash, intercompany accounts, debt and equity). 3 Company Website SoCalGas' website address is http://www.socalgas.com/ and the website address of PE's parent company, Sempra Energy, is http://www.sempra.com/investor.htm. The company makes available free of charge via a hyperlink on its website to Sempra Energy's website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the Securities and Exchange Commission. GOVERNMENT REGULATION Local Regulation SoCalGas has gas franchises with the 240 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. Some franchises have fixed terms, such as that for the city of Los Angeles, which expires in 2012. 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 2048. California Utility Regulation The State of California Legislature, from time to time, passes laws that regulate SoCalGas' operations. For example, in 1999, the legislature enacted a law addressing natural gas industry restructuring. The CPUC, which consists of five commissioners appointed by the Governor of California for staggered six-year terms, regulates 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 CPUC also regulates the relationship of utilities with their holding companies and is currently conducting an investigation into this relationship. United States Utility Regulation The FERC regulates the interstate sale and transportation of natural gas, the uniform systems of accounts and rates of depreciation. Both the FERC and CPUC are currently investigating prices charged to the California investor-owned utilities (IOUs) by various suppliers of natural gas and electricity. Licenses and Permits SoCalGas obtains a number of permits, authorizations and licenses in connection with the transmission and distribution of natural gas. They require periodic renewal, which results in continuing regulation by the granting agency. Other regulatory matters are described in Note 9 of the notes to Consolidated Financial Statements herein. 4 SOURCES OF REVENUE Information on this topic is provided in Note 1 of the notes to Consolidated Financial Statements herein. NATURAL GAS OPERATIONS SoCalGas purchases, sells, distributes, stores and transports natural gas. It owns and operates a natural gas distribution, transmission and storage system that supplies natural gas to 18.9 million end-use customers throughout a 23,000-square mile service territory from San Luis Obispo in the north, to the Mexican border in the south, and 535 cities, excluding the City of Long Beach and SDG&E's service territory in the County of San Diego. SoCalGas also transports gas to about 1,300 utility electric generation (UEG), wholesale, large commercial, industrial and off-system (outside the company's normal service territory) customers. SoCalGas offers two basic utility services: sale of natural gas and transportation of natural gas. Natural gas service is also provided on a wholesale basis to the distribution systems of the City of Long Beach, Southwest Gas Corporation and SDG&E, an affiliated company. Supplies of Natural Gas SoCalGas buys natural gas under several short-term and long-term contracts. Short-term purchases are from various suppliers and are primarily based on monthly spot-market prices. SoCalGas transports natural gas under long-term firm pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SoCalGas has commitments for firm pipeline capacity under contracts with pipeline companies that expire at various dates through 2006. Most of the natural gas purchased and delivered by SoCalGas is produced outside of California. These supplies are delivered to SoCalGas' 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. 5 The following table shows the sources of natural gas deliveries from 1998 through 2002:
Years Ended December 31 ------------------------------------------------- 2002 2001 2000 1999 1998 - ----------------------------------------------------------------------------------------- Purchases in billions of cubic feet Gas purchases - commodity portion 379 367 360 391 374 Customer-owned and exchange receipts 640 837 755 637 637 Storage withdrawal (injection) - net 3 (27) 39 (6) (28) Company use and unaccounted for (18) (24) (21) (16) (21) ------- ------- ------- ------- ------- Net deliveries 1,004 1,153 1,133 1,006 962 ======= ======= ======= ======= ======= Purchases in millions of dollars Commodity costs $1,101 $1,997 $1,243 $ 916 $ 774 Fixed charges* 128 128 128 147 174 ------- ------- ------- ------- ------- Total purchases $1,229 $2,125 $1,371 $1,063 $ 948 ======= ======= ======= ======= ======= Average commodity cost of purchases (dollars per thousand cubic feet)** $ 2.90 $ 5.44 $ 3.45 $ 2.34 $ 2.07 ======= ======= ======= ======= ======= * 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. ** The average commodity cost of natural gas purchased excludes fixed charges.
Market-sensitive natural gas supplies (supplies purchased on the spot market as well as under longer-term contracts, ranging from one month to two years, based on spot prices) accounted for 100 percent of total natural gas volumes purchased by SoCalGas. The annual average price of natural gas at the California/Arizona border was $3.14/million British thermal units (mmbtu) in 2002, compared with $7.27/mmbtu in 2001 and $6.25/mmbtu in 2000. Supply/demand imbalances and a number of other factors associated with California's energy crisis from late 2000 through early 2001 resulted in higher natural gas prices during that period. Prices for natural gas decreased in the later part of 2001 and increased toward the end of 2002. As of December 31, 2002, the average spot cash price at the California/Arizona border was $4.47/mmbtu. The cost of gas purchased may vary and can exceed the annual average price. During 2002, SoCalGas delivered 1,004 billion cubic feet (bcf) of natural gas. Approximately 65 percent of these deliveries were customer- owned natural gas for which SoCalGas provided transportation services. The remaining natural gas deliveries were purchased by SoCalGas and resold to customers. 6 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 UEG, wholesale, large commercial, industrial and off-system (outside the company's normal service territory) customers. Of the 5.3 million meters in SoCalGas' service territory, only 1,300 serve the noncore market. Most core customers purchase natural gas directly from SoCalGas. Core customers are permitted to aggregate their natural gas requirement and, for up to 10 percent of SoCalGas' core market, to purchase natural gas directly from brokers or producers. The CPUC tentatively authorized the removal of the 10 percent limit, but this has yet to be implemented. SoCalGas continues to be obligated to purchase reliable supplies of natural gas to serve the requirements of its core customers. In early 2002, the California Utilities filed an application with the CPUC to combine their core procurement portfolios. On August 22, 2002, the CPUC issued an interim decision denying the request, pending completion of the CPUC's ongoing investigation of market power issues. The CPUC ordered that utility procurement services offered to noncore customers be phased out sometime in 2003. Noncore customers would have the option to either become core customers, and continue to receive utility procurement services, or remain noncore customers and purchase their natural gas from other sources, such as brokers or producers. Noncore customers would also have to make arrangements to deliver their purchases to SoCalGas' receipt points for delivery through SoCalGas' transmission and distribution system. The proposed implementation of the order has encountered significant opposition and the CPUC is reconsidering its decision. In 2002, 85 percent of the CPUC-authorized natural gas margin was allocated to the core customers, with 15 percent allocated to the noncore customers. Although revenues from transportation throughput is less than for natural gas sales, SoCalGas generally earns the same margin whether SoCalGas buys the natural gas and sells it to the customer or transports natural gas already owned by the customer. SoCalGas 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, 2002, SoCalGas was storing approximately 34 bcf of customer-owned gas. Demand for Natural Gas Natural gas is a principal energy source for residential, commercial, industrial and UEG plant 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. SoCalGas added 61,000 new customer meters in 2002 and 59,000 in 7 2001, representing growth rates of 1.2 percent and 1.1 percent, respectively. SoCalGas expects that its growth rate for 2003 will approximate that of 2002. During 2002, 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. Demand for natural gas by noncore customers is very sensitive to the price of competing fuels. Although the number of noncore customers in 2002 was only 1,300 they accounted for approximately 8 percent of the authorized natural gas revenues and 65 percent of total natural gas volumes. External factors such as weather, the price of electricity, electric deregulation, the use of hydroelectric power, competing pipelines and general economic conditions can result in significant shifts in demand and market price. 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. Effective March 31, 1998, electric industry restructuring gave California electric utilities the option of purchasing energy for their customers from 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 SoCalGas natural gas operations, future volumes of natural gas transported for electric generating plant customers may be significantly affected to the extent that regulatory changes divert electricity generation from SoCalGas' service area. Other The Pipeline Safety Improvement Act of 2002, which became public law on December 17, 2002, requires that baseline inspections be completed over a ten-year period, with 50 percent of the inspections complete at the end of five years. Related to these inspections and potential retrofits, the company estimates that it will have $2.8 million in operating and maintenance expense each year and $23 million in capital expenditures. 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 9 and 10 of the notes to Consolidated Financial Statements herein. RATES AND REGULATION Natural Gas Industry Restructuring The natural gas industry in California experienced an initial phase of restructuring during the 1980s. In December 2001 the CPUC issued a decision adopting provisions affecting the structure of the natural gas industry in California, some of which could introduce additional volatility into the earnings of SoCalGas and other market participants. During 2002 the California Utilities filed a proposed implementation schedule and revised tariffs and rules required for implementation. However, protests of these compliance filings were filed, and the CPUC has not yet authorized implementation of most of the provisions of its decision. Additional information on natural gas industry restructuring is provided in "Management's Discussion and Analysis of Financial 8 Condition and Results of Operations" and in Note 9 of the notes to Consolidated Financial Statements herein. 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 through balancing accounts authorized by the CPUC. As a result, fluctuations in commodity costs and consumption levels do not affect earnings from SoCalGas' operations. In December 2002, the CPUC issued a decision approving 100 percent balancing account treatment for variances between forecast and actual for SoCalGas' noncore revenues and throughput (see BCAP below). Additional information on balancing accounts is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 1 of the notes to Consolidated Financial Statements herein. Biennial Cost Allocation Proceeding (BCAP) Rates to recover the changes in the cost of natural gas transportation services are determined in the BCAP. The mechanism in effect through the end of 2002 largely eliminated the effect on SoCalGas' income of variances in customer demand and natural gas transportation costs and is subject to the limitations of the Gas Cost Incentive Mechanism (GCIM) described below. In December 2002, the CPUC issued a decision approving 100 percent balancing account treatment for variances between forecast and actual for SoCalGas' noncore revenues and throughput. The change eliminates the impact on earnings from any throughput and revenue variances compared to adopted forecast levels, effective January 1, 2003. Additional information on the BCAP is provided in Note 9 of the notes to Consolidated Financial Statements herein. Gas Cost Incentive Mechanism 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 9 of the notes to Consolidated Financial Statements herein. Cost of Capital The authorized cost of capital is determined by an automatic adjustment mechanism based on changes in certain capital market indices. Additional information on SoCalGas' cost of capital is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 9 of the notes to Consolidated Financial Statements herein. Performance-Based Regulation (PBR) To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC adopted PBR for SoCalGas effective in 1997. PBR has resulted in modification to the general rate case and certain other regulatory proceedings for SoCalGas. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and productivity goals, rather than relying solely on expanding utility plant to increase 9 earnings. The three areas that are eligible for PBR rewards are operational incentives based on measurements of safety, reliability and customer satisfaction; demand-side management (DSM) rewards based on the effectiveness of the programs; and natural gas procurement rewards. Rewards resulting from PBR are not included in the company's earnings before they are approved by the CPUC. Additional information on SoCalGas' PBR mechanism is provided in "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in Note 9 of the notes to Consolidated Financial Statements herein. ENVIRONMENTAL MATTERS Discussions about environmental issues affecting the company are included in Note 10 of the notes to Consolidated Financial Statements herein. The following additional information should be read in conjunction with those discussions. Hazardous Substances In 1994, the CPUC approved the Hazardous Waste Collaborative Memorandum account, allowing California's IOUs to recover their hazardous waste cleanup costs, including those related to Superfund sites or similar sites requiring cleanup. Recovery of 90 percent of hazardous waste cleanup costs and related third-party litigation costs and 70 percent of the related insurance-litigation expenses is permitted. In addition, the company has the opportunity to retain a percentage of any insurance recoveries to offset the 10 percent of costs not recovered in rates. During the early 1900s, SoCalGas and its predecessors manufactured gas from coal or oil. The manufacturing sites often have become contaminated with the hazardous residual by-products of the process. SoCalGas has identified 42 such sites at which it (together with other users as to 21 of these sites) may have cleanup obligations. Preliminary investigations, at a minimum, have been completed on 41 of the sites. As of December 31, 2002, 22 of these sites have been remediated, of which 18 have received certification from the California Environmental Protection Agency (EPA). At December 31, 2002, SoCalGas' estimated remaining investigation and remediation liability for all of these sites was $42.6 million. SoCalGas lawfully disposes of wastes at permitted facilities owned and operated by other entities. Operations at these facilities may result in actual or threatened risks to the environment or public health. Under California law, businesses that arrange for legal disposal of wastes at a permitted facility from which wastes are later released, or threaten to be released, can be held financially responsible for corrective actions at the facility. SoCalGas has been named as a potentially responsible party (PRP) for two landfill sites and five industrial waste disposal sites, from which releases have occurred. Remedial actions and negotiations with other PRPs and the United States 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 $0.7 million for the first site and $10.4 million for the second site. Since 1987, $11.9 million has been spent ($6.5 million in 2002), including $6.4 million for two consent decrees to settle and liquidate all remaining liabilities at the second site. 10 At December 31, 2002, the company's estimated remaining investigation and remediation liability related to hazardous waste sites, including the manufactured gas sites, was $42.6 million, of which 90 percent is authorized to be recovered through the Hazardous Waste Collaborative mechanism. The company believes that any costs not ultimately recovered through rates, insurance or other means 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. Air and Water Quality California's air quality standards are more restrictive than federal standards. The transmission and distribution of natural gas require the operation of compressor stations, which are subject to increasingly stringent air-quality standards. Costs to comply with these standards are recovered in rates. OTHER MATTERS 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 operating costs. The CPUC has authorized SoCalGas to recover its operating costs associated with RD&D. SoCalGas' annual RD&D costs have averaged $5.9 million over the past three years. Employees of Registrant As of December 31, 2002 SoCalGas had 6,230 employees, compared to 6,063 at December 31, 2001. Labor Relations Field, technical and most clerical employees at SoCalGas are represented by the Utility Workers' Union of America or the International Chemical Workers' Council. The new collective bargaining agreement for field, technical and most clerical employees at SoCalGas has been negotiated. The new agreement on wages, hours and working conditions is in effect through December 31, 2004, and the agreement covering medical, dental and vision benefits is in effect through December 31, 2003. At December 31, 2002, the agreement covering the pension plan, savings plan and life insurance expired. The company and the union have agreed to two successive one-month extensions with the last extension to expire on February 28, 2003. Negotiations are continuing and an agreement is expected in the next several weeks. 11 ITEM 2. PROPERTIES Natural Gas Properties At December 31, 2002, SoCalGas' natural gas facilities included approximately 2,846 miles of transmission and storage pipeline, 46,181 miles of distribution pipeline and 45,215 miles of service piping. They also included 11 transmission compressor stations and 4 underground storage reservoirs, with a combined working capacity of 118 bcf. Other Properties 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 2011. The lease has six separate five-year renewal options. The company owns or leases other offices, operating and maintenance centers, shops, service facilities and equipment necessary in the conduct of its business. ITEM 3. LEGAL PROCEEDINGS Except for the matters described in Note 10 of the notes to Consolidated Financial Statements or referred to elsewhere in this Annual Report, neither the companies nor their 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 All of the issued and outstanding common stock of PE is owned by Sempra Energy. The information required by Item 5 concerning dividends declared is included in the "Statements of Consolidated Changes in Shareholders' Equity" set forth in Item 8 of this Annual Report herein. 12 ITEM 6. SELECTED FINANCIAL DATA
(Dollars in millions) At December 31, or for the years then ended - ----------------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ------ ------ ------ ------ ------ Pacific Enterprises: Income Statement Data: Operating revenues $ 2,858 $ 3,716 $ 2,854 $ 2,569 $ 2,472 Operating income $ 246 $ 269 $ 263 $ 271 $ 218 Dividends on preferred stock $ 4 $ 4 $ 4 $ 4 $ 4 Earnings applicable to common shares $ 209 $ 202 $ 207 $ 180 $ 143 Balance Sheet Data: Total assets $ 4,559 $ 4,161 $ 4,756 $ 4,110 $ 4,571 Long-term debt $ 657 $ 579 $ 821 $ 939 $ 985 Short-term debt (a) $ 175 $ 150 $ 120 $ 30 $ 249 Shareholders' equity $ 1,684 $ 1,574 $ 1,526 $ 1,426 $ 1,547 (a) Includes long-term debt due within one year. Since Pacific Enterprises is a wholly owned subsidiary of Sempra Energy, per share data is not provided. (Dollars in millions) At December 31, or for the years then ended - ----------------------------------------------------------------------------------- 2002 2001 2000 1999 1998 ------ ------ ------ ------ ------ SoCalGas: Income Statement Data: Operating revenues $ 2,858 $ 3,716 $ 2,854 $ 2,569 $ 2,427 Operating income $ 242 $ 273 $ 266 $ 268 $ 238 Dividends on preferred Stock $ 1 $ 1 $ 1 $ 1 $ 1 Earnings applicable to common shares $ 212 $ 207 $ 206 $ 200 $ 158 Balance Sheet Data: Total assets $ 4,079 $ 3,733 $ 4,128 $ 3,452 $ 3,834 Long-term debt $ 657 $ 579 $ 821 $ 939 $ 967 Short-term debt (a) $ 175 $ 150 $ 120 $ 30 $ 75 Shareholders' equity $ 1,340 $ 1,327 $ 1,309 $ 1,310 $ 1,382 (a) Includes long-term debt due within one year.
Since SoCalGas is a wholly owned subsidiary of Pacific Enterprises, per share data is not provided. This data should be read in conjunction with the Consolidated Financial Statements and the notes to Consolidated Financial Statements contained herein. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -- Pacific Enterprises and Southern California Gas Company INTRODUCTION This section includes management's discussion and analysis of operating results from 2000 through 2002, and provides information about the capital resources, liquidity and financial performance of Pacific 13 Enterprises (PE) and Southern California Gas Company (SoCalGas). SoCalGas, PE or the two together are referred to as "the company" herein, the distinction being indicated by the context. This section also focuses on the major factors expected to influence future operating results and discusses investment and financing activities and plans. It should be read in conjunction with the Consolidated Financial Statements included herein. PE is an energy services company whose only direct subsidiary is SoCalGas, the nation's largest natural gas distribution utility. SoCalGas owns and operates a natural gas distribution, transmission and storage system supplying natural gas throughout a 23,000-square mile service territory. Its service territory extends from San Luis Obispo on the north to the Mexican border in the south, and 535 cities, excluding the City of Long Beach and San Diego County. SoCalGas provides natural gas service to residential, commercial, industrial, utility electric generation and wholesale customers, through 5.3 million meters in a service area with a population of 18.9 million. Business Combination Sempra Energy (the Parent) was formed to serve as a holding company for PE, the parent corporation of SoCalGas, and Enova Corporation (Enova), the parent corporation of San Diego Gas & Electric (SDG&E), in a tax- free business combination that became effective on June 26, 1998. RESULTS OF OPERATIONS To understand the operations and financial results of the company, it is important to understand the ratemaking procedures to which the company is subject. SoCalGas is regulated primarily by the California Public Utilities Commission (CPUC). It is the responsibility of the CPUC to regulate investor-owned utilities (IOUs) in a manner that serves the best interests of their customers while providing the IOUs the opportunity to earn a reasonable return on investment. The natural gas industry experienced an initial phase of restructuring during the 1980s by deregulating natural gas sales to noncore customers. In December 2001, the CPUC issued a decision related to natural gas industry restructuring, adopting several provisions that the company believes will make natural gas service more reliable, more efficient and better tailored to the desires of customers. The CPUC anticipated implementation during 2002; however, implementation has been delayed. In connection with restructuring of the natural gas industry, the company 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, such as demand side management and customer growth, rather than solely to expanding utility plant. See additional discussion of these situations under "Factors Influencing Future Performance" and in Note 9 of the notes to Consolidated Financial Statements. The table below summarizes SoCalGas' natural gas volumes and revenues by customer class: 14 NATURAL GAS SALES, TRANSPORTATION AND EXCHANGE (Dollars in millions, volumes in billion cubic feet) For the years ended December 31
Natural Gas Sales Transportation & Exchange Total -------------------------------------------------------------------- Volumes Revenue Volumes Revenue Volumes Revenue -------------------------------------------------------------------- 2002: Residential 256 $1,843 2 $ 7 258 $1,850 Commercial and industrial 100 537 289 168 389 705 Electric generation plants -- -- 201 38 201 38 Wholesale -- -- 156 23 156 23 ----------------------------------------------------------------- 356 $2,380 648 $236 1,004 2,616 Balancing accounts and other 242 --------- Total $2,858 - --------------------------------------------------------------------------------------------- 2001: Residential 263 $2,336 2 $ 6 265 $2,342 Commercial and industrial 95 670 258 157 353 827 Electric generation plants -- -- 361 86 361 86 Wholesale -- -- 174 36 174 36 ----------------------------------------------------------------- 358 $3,006 795 $285 1,153 3,291 Balancing accounts and other 425 --------- Total $3,716 - --------------------------------------------------------------------------------------------- 2000: Residential 251 $2,167 3 $ 12 254 $2,179 Commercial and industrial 86 621 317 209 403 830 Electric generation plants -- -- 310 106 310 106 Wholesale -- -- 166 54 166 54 ----------------------------------------------------------------- 337 $2,788 796 $381 1,133 3,169 Balancing accounts and other (315) --------- Total $2,854 - ---------------------------------------------------------------------------------------------
2002 Compared to 2001 Natural Gas Revenue and Cost of Gas Distributed. Natural gas revenues decreased to $2.9 billion in 2002 from $3.7 billion in 2001, and the cost of natural gas distributed decreased to $1.2 billion in 2002 from $2.1 billion in 2001. These decreases were due to lower average natural gas commodity prices and decreased transportation for electric generation plants. For the fourth quarter, natural gas revenues increased to $859 million in 2002 from $681 million in 2001, and the cost of natural gas distributed increased to $384 million in 2002 from $270 million in 2001. These increases were due primarily to increased natural gas prices in the fourth quarter of 2002. Under the current regulatory framework, changes in core-market natural gas prices (natural gas purchased for customers that are primarily residential and small commercial and industrial customers, without alternative fuel capability) or consumption levels do not affect net income, since core customer rates generally recover the actual cost of natural gas on a substantially concurrent basis and consumption levels are fully balanced. However, SoCalGas' Gas Cost Incentive Mechanism (GCIM) allows SoCalGas to share in the savings or costs from buying 15 natural gas for customers below or above monthly benchmarks. 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 between customers and shareholders. See further discussion in Notes 1 and 9 of the notes to Consolidated Financial Statements. Other Operating Expenses. Other operating expenses increased in 2002 compared to 2001 due to higher legal costs, labor and employee benefits costs, and an increase in operating costs, including operating costs that are associated with balancing accounts. Other Income. Other income and deductions consist primarily of interest income from short-term investments and interest income/expense from regulatory balancing accounts. This increased in 2002 due to lower regulatory interest expense, offset by lower interest income from affiliates. Additionally, PE earned higher rental income in 2002. Interest Expense. Interest expense decreased in 2002 due to SoCalGas' repayments of $270 million in long-term debt during the fourth quarter of 2001, and due to lower interest expense to affiliates. Income Taxes. Income tax expense at SoCalGas increased in 2002 as compared to 2001 due to higher income before taxes. Net Income. Net income for SoCalGas increased to $213 million in 2002 compared to $208 million in 2001. This increase was due primarily to decreased interest expense in 2002, offset partially by increased depreciation and the 2000 GCIM award recorded in 2001. Additionally, PE's net income included less interest income from affiliates in 2002. Net income for the fourth quarter of 2002 decreased compared to the fourth quarter of 2001 for both SoCalGas and PE due mainly to increased operating costs, partially offset by lower interest expense in 2002. 2001 Compared to 2000 Natural Gas Revenue and Cost of Gas Distributed. Natural gas revenues increased to $3.7 billion in 2001 from $2.9 billion in 2000, and the cost of natural gas distributed increased to $2.1 billion in 2001 from $1.4 billion in 2000. These increases were due to higher average gas prices and higher volumes of natural gas sales in 2001. For the fourth quarter, natural gas revenues decreased to $681 million in 2001 from $804 million in 2000, and the cost of natural gas distributed decreased to $270 million in 2001 from $402 million in 2000. These decreases were attributable to lower natural gas costs in the fourth quarter of 2001. Other Operating Expenses. Other operating expenses increased in 2001 compared to 2000 due to higher costs for company-use fuel (as a result of higher natural gas prices), higher employee benefit expenses and operation costs covered by balancing accounts. Other Income. Other income and deductions consist primarily of interest income from short-term investments and interest income and/or expense from regulatory balancing accounts. This decreased in 2001 compared to 2000 primarily due to lower interest from affiliates, and due to the 2000 gain on the sale of SoCalGas' investment in Plug Power. 16 Interest Expense. Interest expense decreased in 2001 as compared to 2000 due to SoCalGas' repayments of $270 million in long-term debt during the fourth quarter of 2001, and due to lower interest expense to affiliates. Income Taxes. Income tax expense decreased in 2001 as compared to 2000 due to lower income before taxes and higher deductions related to capitalized costs. Net Income. Net income for SoCalGas increased to $208 million in 2001 compared to $207 million in 2000 primarily due to higher gas volumes in 2001, offset by the gain on sale of SoCalGas' investment in Plug Power during 2000 and less interest income from affiliates in 2001. Net income for the fourth quarter of 2001 decreased compared to the fourth quarter of 2000 for both SoCalGas and PE, primarily due to the sale of the Plug Power investment mentioned above. CAPITAL RESOURCES AND LIQUIDITY SoCalGas' operations are the major source of liquidity. In addition, working capital requirements can be met through the issuance of short- term and long-term debt. Cash requirements primarily consist of capital expenditures for utility plant. At December 31, 2002, the company had $22 million in cash and $800 million in unused, committed lines of credit (of which SoCalGas had $300 million in unused lines of credit and PE had $500 million for the purpose of providing loans to Sempra Energy Global Enterprises (Global)). Management believes that cash flows from operations and debt issuances will be adequate to finance capital expenditure requirements, and other commitments. Management continues to regularly monitor SoCalGas' ability to adequately meet the needs of its operating, financing and investing activities. CASH FLOWS FROM OPERATING ACTIVITIES Net cash provided by operating activities totaled $521 million, $300 million and $772 million for 2002, 2001 and 2000, respectively. The increase in cash flows from operations was primarily due to the payment of higher accounts payable in 2001 and the increase in regulatory balancing accounts, partially offset by higher accounts receivable at the end of 2002. The increase in accounts receivable was due to higher natural gas costs towards the end of 2002. See further discussion on the 2001 impact of regulatory balancing accounts activity below. The decrease in cash flows from operating activities in 2001 compared to 2000 was primarily attributable to the decrease in accounts payable due to lower natural gas costs in 2001 compared to 2000 and the result of balancing account activity at SoCalGas. This included returns of prior overcollections and the temporary effects of higher-than-expected costs of natural gas and public-purpose programs and lower-than-expected sales volumes. The decrease was partially offset by lower accounts receivable balances at the end of 2001. 17 CASH FLOWS FROM INVESTING ACTIVITIES Net cash used in investing activities totaled $508 million, $74 million and $444 million for 2002, 2001 and 2000, respectively. The increase in cash used in investing activities in 2002 compared to 2001 was primarily due to increased capital expenditures and advances to Sempra Energy, which are payable on demand. For 2001, cash flows used in investing activities decreased from 2000 due to loan repayments made by Sempra Energy to the company in 2001 compared to loans made to Sempra Energy in 2000, partially offset by an increase in capital expenditures for utility plant. Capital Expenditures for Utility Plant Capital expenditures were $331 million in 2002, compared to $294 million and $198 million in 2001 and 2000, respectively. Increases in capital expenditures in 2002 and 2001 were primarily due to improvements to the natural gas distribution systems and expansion of pipeline capacity to meet increased demand by electric generators and by commercial and industrial customers. The expansion of SoCalGas' pipeline capacity was completed in 2002. Future Capital Expenditures Significant capital expenditures in 2003 are expected to include $350 million for improvements to the distribution system. These expenditures are expected to be financed by operations and security issuances. Over the next five years, the company expects to make capital expenditures of approximately $2 billion. Construction programs are periodically reviewed and revised by the company in response to changes in economic conditions, competition, customer growth, inflation, customer rates, the cost of capital, and environmental and regulatory requirements. The company's level of construction expenditures in the next few years may vary substantially, and will depend on the availability of financing and business opportunities providing desirable rates of return. The company's intention is to finance any sizeable expenditures so as to maintain the company's strong investment-grade ratings and capital structure. Smaller expenditures will be made by the use of existing liquidity. CASH FLOWS FROM FINANCING ACTIVITIES Net cash used in financing activities totaled $4 million, $418 million and $134 million for 2002, 2001 and 2000, respectively. Net cash used in financing activities decreased from 2001 due primarily to the decrease in common dividends paid and lower debt repayments, partially offset by the issuance of long-term debt of $250 million. Net cash used in financing activities increased in 2001 compared to 2000 primarily due to the increase in long-term debt repayments and higher dividends paid by PE in 2001. 18 Long-Term and Short-Term Debt In October 2002, SoCalGas publicly offered and sold $250 million of 4.80% first-mortgage bonds, maturing on October 1, 2012. The bonds are not subject to a sinking fund and are not redeemable prior to maturity except through a make-whole mechanism. Proceeds from the bond sale have become part of the company's general treasury funds to replenish amounts previously expended to refund and retire indebtedness and will be used for working capital and other general corporate purposes. On September 30, 2002, SoCalGas cancelled a fixed-to-variable interest- rate swap on $175 million of first-mortgage bonds. The $6 million gain on the transaction is being amortized over the life of the bonds, which mature in 2025. In August 2002, SoCalGas paid off $100 million of 6.875% first-mortgage bonds at maturity. In 2002, cash was used for the repayment of $50 million of short-term debt. Cash was used for the repayment of $150 million of first-mortgage bonds and $120 million of unsecured notes in 2001. Also in 2001, PE had an offsetting increase of $50 million in short-term debt. In May 2002, SDG&E and SoCalGas replaced their individual revolving lines of credit with a combined revolving credit agreement under which each utility may individually borrow up to $300 million, subject to a combined borrowing limit for both utilities of $500 million. Each utility's revolving credit line expires on May 16, 2003, at which time it may convert its then outstanding borrowings to a one-year term loan subject to having obtained any requisite regulatory approvals. Borrowings under the agreement, which are available for general corporate purposes including back-up support for commercial paper and variable-rate long-term debt, would bear interest at rates varying with market rates and the borrowing utility's credit rating. The agreement requires each utility to maintain a debt-to-total capitalization ratio (as defined in the agreement) of not to exceed 60 percent. The rights, obligations and covenants of each utility under the agreement are individual rather than joint with those of the other utility, and a default by one utility would not constitute a default by the other. Dividends Dividends paid to Sempra Energy amounted to $100 million in 2002, compared to $190 million in 2001 and $100 million in 2000. Dividends paid by SoCalGas to PE amounted to $200 million, $190 million and $200 million in 2002, 2001 and 2000, respectively. The payment of future dividends and the amount thereof are within the discretion of the companies' boards of directors. The CPUC's regulation of SoCalGas' capital structure limits the amounts that are available for loans and dividends to Sempra Energy from SoCalGas. At December 31, 2002, the company could have provided a total of $250 million to Sempra Energy. At December 31, 2002, SoCalGas had loans to Sempra Energy of $86 million. Capitalization Total capitalization, including the current portion of long-term debt at December 31, 2002 was $2.5 billion of which $2.2 billion applied to 19 SoCalGas. The debt-to-capitalization ratios were 33 percent and 38 percent at December 31, 2002 for PE and SoCalGas, respectively. Significant changes in capitalization during 2002 included long-term borrowings and dividends. Cash and Cash Equivalents Cash and cash equivalents are available for investment in projects consistent with the company's strategic direction, retirement of debt, payment of dividends and other corporate purposes. In addition to cash generated from ongoing operations, PE has a credit agreement which permits short-term borrowings of up to $500 million. This agreement, which expires in April 2003, has not yet been used as of December 31, 2002. At December 31, 2002, SoCalGas had $22 million of cash and $300 million of revolving lines of credit. Management believes these amounts and cash flows from operations and new debt issuances will be adequate to finance capital expenditures and other commitments. Commitments The following is a summary of the company's principal contractual commitments at December 31, 2002 (dollars in millions). Liabilities reflecting fixed price contracts and other derivatives are excluded as they are primarily offset against regulatory assets and would be recovered from customers through the ratemaking process. Additional information concerning commitments is provided above and in Notes 3 and 10 of the notes to Consolidated Financial Statements.
By Period ---------------------------------------------------- 2004 2006 and and Description 2003 2005 2007 Thereafter Total - -------------------------------------------------------------------------------- SOCALGAS Long-term debt $ 175 $ -- $ 8 $ 649 $ 832 Natural gas contracts 839 395 110 -- 1,344 Operating leases 41 79 80 154 354 Environmental commitments 11 21 11 -- 43 ---------------------------------------------------- Total 1,066 495 209 803 2,573 PE - operating leases 13 26 26 35 100 ---------------------------------------------------- Total PE consolidated $1,079 $ 521 $ 235 $ 838 $2,673 ==================================================== Credit Ratings As of January 31, 2003, company credit ratings were as follows: S&P Moody's Fitch - ------------------------------------------------------------------- SOCALGAS Secured Debt A+ A1 AA Unsecured Debt A A2 AA- Preferred Stock A- Baa1 A+ Commercial Paper A-1 P-1 F1+ --------------------------------------- PE - Preferred Stock BBB+ - A+ ---------------------------------------
20 As of January 31, 2003, SoCalGas has a stable outlook rating from all three credit rating agencies. FACTORS INFLUENCING FUTURE PERFORMANCE Performance of PE in the near future will depend on the results of SoCalGas. The factors influencing future performance are summarized below. Natural Gas Restructuring and Gas Rates On December 11, 2001, the CPUC issued a decision adopting the following provisions affecting the structure of the natural gas industry in California, some of which could introduce additional volatility into the earnings of the company and other market participants: a system for shippers to hold firm, tradable rights to capacity on SoCalGas' major gas transmission lines, with SoCalGas' shareholders at risk for whether market demand for these rights will cover the cost of these facilities; a further unbundling of SoCalGas' storage services, giving SoCalGas greater upward pricing flexibility (except for storage service for core customers) but with increased shareholder risk for whether market demand will cover storage costs; new balancing services, including separate core and noncore balancing provisions; a reallocation among customer classes of the cost of interstate pipeline capacity held by SoCalGas and an unbundling of interstate capacity for natural gas marketers serving core customers; and the elimination of noncore customers' option to obtain natural gas procurement service from SoCalGas and SDG&E. During 2002 the California Utilities filed a proposed implementation schedule and revised tariffs and rules required for implementation. However, protests of these compliance filings were filed and the CPUC has not yet authorized implementation of most of the provisions of its decision. On December 30, 2002, the CPUC deferred acting on a plan to implement its decision. Allowed Rates of Return Effective January 1, 2003, SoCalGas' authorized rate of return on ratebase (ROR) is 8.68 percent and its rate of return on common equity (ROE) is 10.82 percent. These rates will be effective until the next periodic review by the CPUC unless market interest-rate changes are large enough to trigger an automatic adjustment prior thereto, which last occurred in October 2002 and adjusted rates downward from the previous 9.49 percent (ROR) and 11.6 percent (ROE) to the current levels. This change results in a revenue requirement decrease of $10.5 million. SoCalGas can earn more than the authorized rate by controlling costs below approved levels or by achieving favorable results in certain areas such as various incentive mechanisms. In addition, earnings are affected by customer growth. Cost of Service (COS) and Performance-Based Regulation The COS and PBR cases for SoCalGas were filed on December 20, 2002. The filings outline projected expenses (excluding the commodity cost of natural gas consumed by customers or expenses for programs such as low- income assistance) and revenue requirements for 2004 and a formula for 2005 through 2008. SoCalGas' cost of service study proposes an increase in natural gas base rate revenues of $130 million. The filings also requested a continuance and expansion of PBR in terms of earnings 21 sharing and performance service standards that include both reward and penalty provisions related to customer satisfaction, employee safety and system reliability. The resulting new base rates are expected to be effective on January 1, 2004. A CPUC decision is expected in late 2003. SoCalGas' profitability is dependent upon its ability to control costs within base rates. SoCalGas' PBR mechanism is in effect through December 31, 2003, at which time the mechanism will be updated. That update will include, among other things, a reexamination of the company's reasonable costs of operation to be allowed in rates. The October 10, 2001 decision also denied the company's request to continue equal sharing between ratepayers and shareholders of the estimated savings for the merger discussed in Note 1 and, instead, ordered that all of the estimated 2003 merger savings go to ratepayers. This decision will adversely affect the company's 2003 net income by $24 million. Utility Integration On September 20, 2001, the CPUC approved Sempra Energy's request to integrate the management teams of SoCalGas and SDG&E. The decision retains the separate identities of each utility and is not a merger. Instead, utility integration is a reorganization that consolidates senior management functions of the two utilities and returns to the utilities the majority of shared support services previously provided by Sempra Energy's centralized corporate center. Once implementation is completed, the integration is expected to result in more efficient and effective operations. In a related development, an August 2002 CPUC interim decision denied a request by SoCalGas and SDG&E to combine their natural gas procurement activities at this time, pending completion of the CPUC's ongoing investigation of market power issues. MARKET RISK Market risk is the risk of erosion of the company's cash flows, net income, asset values and equity due to adverse changes in prices for various commodities, and in interest rates. The company's policy is to use derivative physical and financial instruments to reduce its exposure to fluctuations in interest rates, and commodity prices. The company also uses and trades derivative physical and financial instruments in its energy trading and marketing activities. Transactions involving these financial instruments are with major exchanges and other firms believed to be credit worthy. The use of these instruments exposes the company to market and credit risks which, at times, may be concentrated with certain counterparties. There were no unusual concentrations at December 31, 2002, that would indicate an unacceptable level of risk. Credit risks associated with concentration are discussed below under "Credit Risk." The company has adopted corporate-wide policies governing its market- risk management and trading activities. Assisted by the company's Energy Risk Management Group (ERMG), the company's Energy Risk Management Oversight Committee, consisting of senior officers, oversees company- wide energy risk management activities and monitors the results of trading activities to ensure compliance with the company's stated energy-risk management and trading policies. Utility management receives daily information on positions and the ERMG receives information on a delayed basis detailing positions creating market and credit risk for 22 the company, consistent with affiliate rules. The ERMG independently measures and reports the market and credit risk associated with these positions. In addition, the company's risk-management committee monitors 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 interval. The company has adopted the variance/covariance methodology in its calculation of VaR, and uses both the 95-percent and 99-percent confidence intervals. VaR is calculated independently by the ERMG for the company. Historical volatilities and correlations between instruments and positions are used in the calculation. As of December 31, 2002, the total VaR of the company's natural gas positions was not material. The company uses energy derivatives to manage natural gas price risk associated with servicing its load requirements. In addition, the company makes limited use of natural gas derivatives for trading purposes. These instruments can include forward contracts, futures, swaps, options and other contracts. In the case of both price-risk management and trading activities, the use of derivative financial instruments is subject to certain limitations imposed by company policy and regulatory requirements. See the continuing discussion below and Note 7 of the notes to Consolidated Financial Statements for further information regarding the use of energy derivatives by the company. The following discussion of the company's primary market-risk exposures as of December 31, 2002 includes a discussion of how these exposures are managed. Commodity-Price Risk Market risk related to physical commodities is created by volatility in the prices and basis of natural gas. The company's market risk is impacted by changes in volatility and liquidity in the markets in which these commodities or related financial instruments are traded. The company is exposed, in varying degrees, to price risk primarily in the natural gas markets. The company's policy is to manage this risk within a framework that considers the unique markets, and operating and regulatory environments. The company's market risk exposure is limited due to CPUC authorized rate recovery of natural gas purchase, sale and storage activity. However, the company may, at times, be exposed to market risk as a result of activities under SoCalGas' GCIM, which is discussed in Note 9 of the notes to Consolidated Financial Statements. The company manages its risk within the parameters of the company's market-risk management and trading framework. As of December 31, 2002, the company's exposure to market risk was not material. Interest-Rate Risk The company is exposed to fluctuations in interest rates primarily as a result of its long-term debt. The company historically has funded operations through long-term debt issues with fixed interest rates and these interest rates are recovered in utility rates. With the 23 restructuring of the regulatory process, the CPUC has permitted greater flexibility in the use of debt. As a result, some 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. At December 31, 2002, the company had $833 million of fixed-rate debt and no variable-rate debt. Interest on fixed-rate utility debt is fully recovered in rates on a historical cost basis and interest on variable- rate debt is provided for in rates on a forecasted basis. At December 31, 2002, SoCalGas' fixed-rate debt had a one-year VaR of $166 million. At December 31, 2002, the company did not have any outstanding interest- rate swap transactions. See Notes 3 and 7 of the notes to Consolidated Financial Statements for further information regarding these swap transactions. In addition the company is ultimately subject to the effect of interest rate fluctuation on the assets of its pension plan. Credit Risk Credit risk is the risk of loss that would be incurred as a result of nonperformance by counterparties of their contractual obligations. As with market risk, the company has adopted corporate-wide policies governing the management of credit risk. Credit risk management is under the oversight of the Energy Risk Management Oversight Committee, assisted by the ERMG and the company's credit department. Using rigorous models, the company's credit department continuously calculates current and potential credit risk to counterparties to ensure the risk stays within approved limits, and reports this information to the ERMG. The company avoids concentration of counterparties and management believes its credit policies with regard to counterparties significantly reduce overall credit risk. These policies include an evaluation of prospective counterparties' financial condition (including credit ratings), 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. The company periodically enters into interest-rate swap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. The company would be exposed to interest-rate fluctuations on the underlying debt should other parties to the agreement not perform. See the "Interest-Rate Risk" section above for additional information regarding the company's use of interest-rate swap agreements. CRITICAL ACCOUNTING POLICIES Certain accounting policies are viewed by management as critical because their application is the most relevant, judgmental and/or material to 24 the company's financial position and results of operations, and/or because they require the use of material judgments and estimates. The company's most significant accounting policies are described in Note 1 of the notes to Consolidated Financial Statements. The most critical policies, all of which are mandatory under generally accepted accounting principles and the regulations of the Securities and Exchange Commission, are the following: Statement of Financial Accounting Standards (SFAS) 71 "Accounting for the Effects of Certain Types of Regulation," has a significant effect on the way the California Utilities record assets and liabilities, and the related revenues and expenses, that would not otherwise be recorded, absent the principles contained in SFAS 71. SFAS 133 "Accounting for Derivative Instruments and Hedging Activities" and SFAS 138 "Accounting for Certain Derivative Instruments and Certain Hedging Activities," have a significant effect on the balance sheets of the Company but have no significant effect on its income statements because of the principles contained in SFAS 71. In connection with the application of these and other accounting policies, the company makes estimates and judgments about various matters. The most significant of these involve: The collectibility of regulatory and other assets. The likelihood of recovery of various deferred tax assets. Differences between estimates and actual amounts have had significant impacts in the past and are likely to do so in the future. As discussed elsewhere herein, the company uses exchange quotations or other third-party pricing to estimate fair values whenever possible. When no such data is available, it uses internally developed models and other techniques. The assumed collectibility of regulatory assets considers legal and regulatory decisions involving the specific items or similar items. The assumed collectibility of other assets considers the nature of the item, the enforceability of contracts where applicable, the creditworthiness of the other parties and other factors. Costs to fulfill marked-to-market contracts are based on prior experience. The likelihood of deferred tax recovery is based on analyses of the deferred tax assets and the company's expectation of future financial and/or taxable income, based on its strategic planning. Choices among alternative accounting policies that are material to the company's financial statements and information concerning significant estimates have been discussed with the audit committee of the board of directors. NEW ACCOUNTING STANDARDS New pronouncements by the Financial Accounting Standards Board (FASB) that have recently become effective or are yet to be effective are SFAS 142 through SFAS 149 and Interpretations 45 and 46. SFAS 142 affects net income by replacing the amortization of goodwill with periodic reviews thereof for impairment with charges against income when impairment is found. SFAS 143 requires accounting and disclosure changes concerning 25 legal obligations related to future asset retirements. SFAS 144 supercedes SFAS 121 in dealing with other asset impairment issues. SFAS 145 makes technical corrections to previous statements. SFAS 146 deals with exit and disposal activities, replacing Emerging Issues Task Force (EITF) Issue 94-3. SFAS 147 deals with acquisitions of financial institutions. SFAS 148 amends SFAS 123 and adds two additional transition methods to the fair value method of accounting for stock- based compensation. SFAS 149 establishes standards for accounting for financial instruments with characteristics of liabilities and equity. Interpretation 45 clarifies that a guarantor is required to recognize a liability for the fair value of the obligation undertaken in issuing a guarantee. Interpretation 46 addresses consolidation by business enterprises of variable-interest entities (previously referred to as "special-purpose entities" in most cases). See further discussion in Note 1 of the notes to Consolidated Financial Statements. 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," "would" and "should" or similar expressions, or discussions of strategy or of plans are intended to identify forward-looking statements. Forward- looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future results may differ materially from those expressed in these forward-looking statements. Forward-looking 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, legislative and regulatory conditions and developments; actions by the CPUC, the California Legislature, and the FERC; capital market conditions, inflation rates, interest rates and exchange rates; energy and trading markets, including the timing and extent of changes in commodity prices; weather conditions and conservation efforts; war and terrorist attacks; business, regulatory and 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 companies. 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 companies' business described in this report and other reports filed by the companies from time to time with the Securities and Exchange Commission. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK The information required by Item 7A is set forth under "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Market Risk." 26 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA - Pacific Enterprises INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders of Pacific Enterprises: We have audited the accompanying consolidated balance sheets of Pacific Enterprises and subsidiaries (the "Company") as of December 31, 2002 and 2001, and the related statements of consolidated income, cash flows and changes in shareholders' equity for each of the three years in the period ended December 31, 2002. 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 auditing standards generally accepted in the United States of America. 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 Pacific Enterprises and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. /S/ DELOITTE & TOUCHE LLP San Diego, California February 14, 2003 27 PACIFIC ENTERPRISES AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME Dollars in millions
Years ended December 31, 2002 2001 2000 ------ ------ ------ OPERATING REVENUES $2,858 $3,716 $2,854 ------ ------ ------ OPERATING EXPENSES Cost of natural gas distributed 1,192 2,117 1,361 Other operating expenses 879 794 696 Depreciation 276 268 263 Income taxes 172 167 175 Franchise fees and other taxes 93 101 96 ------ ------ ------ Total operating expenses 2,612 3,447 2,591 ------ ------ ------ Operating Income 246 269 263 ------ ------ ------ Other Income and (Deductions) Interest income 11 40 64 Regulatory interest (4) (19) (12) Allowance for equity funds used during construction 10 6 3 Taxes on non-operating income 2 (4) (10) Preferred dividends of subsidiaries (1) (1) (1) Other - net 9 1 3 ------ ------ ------ Total 27 23 47 ------ ------ ------ Interest Charges Long-term debt 40 63 68 Other 23 25 33 Allowance for borrowed funds used during construction (3) (2) (2) ------ ------ ------ Total 60 86 99 ------ ------ ------ Net Income 213 206 211 Preferred Dividend Requirements 4 4 4 ------ ------ ------ Earnings Applicable to Common Shares $ 209 $ 202 $ 207 ====== ====== ====== See notes to Consolidated Financial Statements.
28 PACIFIC ENTERPRISES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS Dollars in millions
December 31, ------------------------ 2002 2001 --------- ---------- ASSETS Utility plant - at original cost $6,701 $6,466 Accumulated depreciation (3,914) (3,710) ------ ------ Utility plant - net 2,787 2,756 ------ ------ Current assets: Cash and cash equivalents 22 13 Accounts receivable - trade 458 413 Accounts receivable - other 44 21 Due from unconsolidated affiliates 83 -- Income taxes receivable 97 20 Deferred income taxes 55 33 Regulatory assets arising from fixed-price contracts and other derivatives 92 85 Fixed-price contracts and other derivatives -- 59 Inventories 76 42 Other 20 4 ------ ------ Total current assets 947 690 ------ ------ Other assets: Due from unconsolidated affiliates 419 409 Regulatory assets arising from fixed-price contracts and other derivatives 233 150 Sundry 173 156 ------ ------ Total other assets 825 715 ------ ------ Total assets $4,559 $4,161 ====== ====== See notes to Consolidated Financial Statements.
29 PACIFIC ENTERPRISES AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS Dollars in millions
December 31, ------------------------ 2002 2001 --------- ----------- CAPITALIZATION AND LIABILITIES Capitalization: Common Stock (600,000,000 shares authorized; 83,917,664 shares outstanding) $1,318 $1,317 Retained earnings 286 177 ------ ------ Total common equity 1,604 1,494 Preferred stock 80 80 ------ ------ Total shareholders' equity 1,684 1,574 Long-term debt 657 579 ------ ------ Total capitalization 2,341 2,153 ------ ------ Current liabilities: Short-term debt -- 50 Accounts payable - trade 200 160 Accounts payable - other 36 80 Due to unconsolidated affiliates 96 169 Regulatory balancing accounts - net 184 158 Interest payable 25 24 Regulatory liabilities 16 18 Fixed-price contracts and other derivatives 96 85 Current portion of long-term debt 175 100 Customer deposits 108 42 Other 265 280 ------ ------ Total current liabilities 1,201 1,166 ------ ------ Deferred credits and other liabilities: Customer advances for construction 37 29 Post-retirement benefits other than pensions 77 88 Deferred income taxes 176 110 Deferred investment tax credits 47 50 Regulatory liabilities 121 86 Fixed-price contracts and other derivatives 233 154 Deferred credits and other liabilities 306 305 Preferred stock of subsidiary 20 20 ------ ------ Total deferred credits and other liabilities 1,017 842 ------ ------ Contingencies and commitments (Note 10) Total liabilities and shareholders' equity $4,559 $4,161 ====== ====== See notes to Consolidated Financial Statements.
30 PACIFIC ENTERPRISES AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS Dollars in millions
Years Ended December 31, 2002 2001 2000 ------- ------- ------- CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 213 $ 206 $ 211 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation 276 268 263 Deferred income taxes and investment tax credits 47 24 5 Changes in other assets 16 (12) 40 Changes in other liabilities -- 32 (16) Changes in working capital components: Accounts and notes receivable (67) 244 (377) Income taxes (78) (71) 84 Fixed-price contracts and other derivatives 60 16 -- Inventories (34) 25 11 Other current assets (4) 4 (75) Accounts payable (4) (171) 191 Due to/from affiliates - net 12 5 35 Regulatory balancing accounts 26 (356) 332 Regulatory assets and liabilities 1 39 (2) Customer deposits 66 8 1 Other current liabilities (9) 39 69 ------- ------- ------- Net cash provided by operating activities 521 300 772 ------- ------- ------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (331) (294) (198) Loans to/from affiliates - net (177) 220 (267) Other - net -- -- 21 ------- ------- ------- Net cash used in investing activities (508) (74) (444) ------- ------- ------- CASH FLOWS FROM FINANCING ACTIVITIES Common dividends paid (100) (190) (100) Preferred dividends paid (4) (4) (4) Issuance of long-term debt 250 -- -- Payments on long-term debt (100) (270) (30) Increase (decrease) in short-term debt (50) 50 -- Other -- (4) -- ------- ------- ------- Net cash used in financing activities (4) (418) (134) ------- ------- ------- Increase (decrease) in cash and cash equivalents 9 (192) 194 Cash and cash equivalents, January 1 13 205 11 ------- ------- ------- Cash and cash equivalents, December 31 $ 22 $ 13 $ 205 ======= ======= ======= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Interest payments, net of amounts capitalized $ 50 $ 83 $ 127 ======= ======= ======= Income tax payments, net of refunds $ 200 $ 209 $ 99 ======= ======= ======= See notes to Consolidated Financial Statements.
31 PACIFIC ENTERPRISES AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY Years ended December 31, 2002, 2001 and 2000 Dollars in millions
Accumulated Other Total Comprehensive Preferred Common Retained Comprehensive Shareholders' Income Stock Stock Earnings Income(Loss) Equity - ------------------------------------------------------------------------------------------------------------------------ Balance at December 31, 1999 $ 80 $1,282 $ 58 $ 6 $1,426 Net income $211 211 211 Other comprehensive income adjustment: Available-for-sale securities (10) (10) (10) Pension 3 3 3 ----- Comprehensive income $204 ===== Preferred stock dividends declared (4) (4) Common stock dividends declared (100) (100) - ----------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2000 80 1,282 165 (1) 1,526 Net income $206 206 206 Other comprehensive income adjustment 1 1 1 ----- Comprehensive income $207 ===== Quasi-reorganization adjustment (Note 1) 35 35 Preferred stock dividends declared (4) (4) Common stock dividends declared (190) (190) - -------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2001 80 1,317 177 -- 1,574 Net income/comprehensive income $213 213 213 Preferred stock dividends declared ===== (4) (4) Common stock dividends declared (100) (100) Capital contribution 1 1 - -------------------------------------------------------------------------------------------------------------------- Balance at December 31, 2002 $ 80 $1,318 $ 286 $ -- $1,684 ===================================================================================================================== See notes to Consolidated Financial Statements.
32 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS NOTE 1. SIGNIFICANT ACCOUNTING POLICIES Business Combination Sempra Energy was formed as a holding company for Enova Corporation (Enova), the parent corporation of San Diego Gas & Electric (SDG&E), and Pacific Enterprises (PE), the parent corporation of Southern California Gas Company (SoCalGas), in connection with a business combination of Enova and PE that was completed on June 26, 1998. Principles of Consolidation The Consolidated Financial Statements include the accounts of PE and its subsidiary, SoCalGas. The financial statements herein are, in one case, the Consolidated Financial Statements of PE and its subsidiary, SoCalGas, and, in the second case, the Consolidated Financial Statements of SoCalGas and its subsidiaries, which comprise less than one percent of SoCalGas' consolidated financial position and results of operations. All material intercompany accounts and transactions have been eliminated. As a subsidiary of Sempra Energy, the company receives certain services therefrom, for which it is charged its allocable share of the cost of such services. Management believes that cost is reasonable, but probably less than if the company had to provide those services itself. Quasi-Reorganization In 1993, PE divested its merchandising operations and most of its oil and natural gas exploration and production business. In connection with the divestitures, PE effected a quasi-reorganization for financial reporting purposes as of December 31, 1992. Certain of the liabilities established in connection with the quasi-reorganization, including various income tax issues, were favorably resolved in 2001, resulting in restoring $35 million to shareholders' equity in that year. This did not affect the calculation of net income or comprehensive income. The remaining liabilities will be resolved in future years. Management believes the provisions established for these matters are adequate. Use of Estimates in the Preparation of the Financial Statements The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of revenues and expenses during the reporting period, and the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements. Actual amounts can differ significantly from those estimates. Basis of Presentation Certain prior-year amounts have been reclassified to conform to the current year's presentation. 33 Regulatory Matters Effects of Regulation The accounting policies of the company 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). The company prepares its financial statements in accordance with the provisions of Statement of Financial Accounting Standards (SFAS) 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 cease to be subject to SFAS 71, or recovery is 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 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" 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 ratebase. The application of SFAS 144 continues to be evaluated in connection with industry restructuring. Information concerning regulatory assets and liabilities is described below in "Revenues", "Regulatory Balancing Accounts," and "Regulatory Assets and Liabilities," and industry restructuring is described in Note 9. Regulatory Balancing Accounts The amounts included in regulatory balancing accounts at December 31, 2002, represent net payables (payables net of receivables) of $184 million and $158 million at December 31, 2002 and 2001, respectively. Balancing accounts provide a mechanism for charging utility customers the amount actually incurred for certain costs, primarily commodity costs. As SoCalGas' natural gas operations are mostly balanced, such fluctuations do not affect earnings. In December 2002, the CPUC issued a decision approving 100 percent balancing account treatment for variances between forecast and actual for SoCalGas' noncore revenues and throughput. The change eliminates the impact on earnings from any throughput and revenue variances compared to adopted forecast levels, effective January 1, 2003. Additional information on regulatory matters is included in Note 9. Regulatory Assets and Liabilities In accordance with the accounting principles of SFAS 71, the company records regulatory assets (which represent probable future revenues associated with certain costs that will be recovered from customers through the rate-making process) and regulatory liabilities (which represent probable future reductions in revenue associated with amounts that are to be credited to customers through the rate-making process). They are amortized over the periods in which the costs are recovered from or refunded to customers in regulatory revenues. 34 Regulatory assets (liabilities) as of December 31 consist of the following: (Dollars in millions) 2002 2001 - ------------------------------------------------------------------------ SoCalGas - --------- Environmental remediation $ 43 $ 55 Fixed-price contracts and other derivatives 325 232 Unamortized loss on retirement of debt - net 38 41 Deferred taxes refundable in rates (164) (158) Employee benefit costs (142) (132) Other 8 5 ------- ------- Total 108 43 PE - Employee benefit costs 80 88 ------- ------- Total PE consolidated $ 188 $ 131 ======= ======= Net regulatory assets are recorded on the Consolidated Balance Sheets at December 31 as follows (dollars in millions): 2002 2001 - ------------------------------------------------------------------------ SoCalGas - -------- Current regulatory assets $ 92 $ 85 Noncurrent regulatory assets 233 150 Current regulatory liabilities (16) (18) Noncurrent regulatory liabilities (201) (174) ------- ------- Total 108 43 PE - Noncurrent regulatory assets 80 88 ------- ------- Total PE consolidated $ 188 $ 131 ======= ======= - ------------------------------------------------------------------------ All the assets earn a return or the cash has not yet been expended and the assets are offset by liabilities that do not incur a carrying cost. Cash and Cash Equivalents Cash equivalents are highly liquid investments with maturities of three months or less at the date of purchase. Collection Allowance The allowance for doubtful accounts receivable was $4 million, $14 million and $19 million at December 31, 2002, 2001 and 2000, respectively. The company recorded a provision (reduction thereof) for doubtful accounts of ($5) million, $9 million and $9 million in 2002, 2001 and 2000, respectively. 35 Inventories At December 31, 2002, inventory included natural gas of $65 million, and materials and supplies of $11 million. The corresponding balances at December 31, 2001 were $34 million and $8 million, respectively. Natural gas is valued by the last-in first-out (LIFO) method. When the inventory is consumed, differences between this LIFO valuation and replacement cost will be reflected in customer rates. Materials and supplies at SoCalGas are generally valued at the lower of average cost or market. Utility Plant Utility plant primarily represents the buildings, equipment and other facilities used by SoCalGas to provide natural gas services. The cost of utility plant includes labor, materials, contract services and related items, and an allowance for funds used during construction (AFUDC). The cost of most retired depreciable utility plant, plus removal costs minus salvage value, is charged to accumulated depreciation. Accumulated depreciation for natural gas utility plant at SoCalGas was $3.9 billion and $3.7 billion at December 31, 2002 and 2001, respectively. Depreciation expense is based on the straight-line method over the useful lives of the assets, an average of 23 years in each of 2002, 2001 and 2000, or a shorter period prescribed by the CPUC. The provision for depreciation as a percentage of average depreciable utility plant was 4.34, 4.33 and 4.36 in 2002, 2001 and 2000, respectively. See Note 9 for discussion of industry restructuring. Maintenance costs are expensed as incurred. AFUDC, which represents the cost of funds used to finance the construction of utility plant, is added to the cost of utility plant. AFUDC also increases income, partly as an offset to interest charges and partly as a component of other income, shown in the Statements of Consolidated Income, although it is not a current source of cash. AFUDC amounted to $13 million, $8 million and $5 million for 2002, 2001 and 2000, respectively. Long-Lived Assets The company periodically evaluates whether events or circumstances have occurred that may affect the recoverability or the estimated useful lives of long-lived assets. Impairment occurs when the estimated future undiscounted cash flows is less than the carrying amount of the assets. If that comparison indicates that the assets' carrying value may be permanently impaired, such potential impairment is measured based on the difference between the carrying amount and the fair value of the assets based on quoted market prices or, if market prices are not available, on the estimated discounted cash flows. This calculation is performed at the lowest level for which separately identifiable cash flows exist. See further discussion of SFAS 144 in "New Accounting Standards". Comprehensive Income Comprehensive income includes 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 foreign-currency translation adjustments, minimum pension liability 36 adjustments, unrealized gains and losses on marketable securities that are classified as available-for-sale, and certain hedging activities. The components of other comprehensive income are shown in the Statements of Consolidated Changes in Shareholders' Equity. Revenues Revenues of SoCalGas are derived from deliveries of natural gas to customers and changes in related regulatory balancing accounts. Revenues from natural gas sales and services are generally recorded under the accrual method and these revenues are recognized upon delivery. Natural gas storage contract revenues are accrued on a monthly basis and reflect reservation, storage and injection charges in accordance with negotiated agreements, which have one-year to three-year terms. Operating revenue includes amounts for services rendered but unbilled (approximately one- half month's deliveries) at the end of each year. Additional information concerning utility revenue recognition is discussed above under "Regulatory Matters." Related Party Transactions - Loans to Unconsolidated Affiliates PE has a promissory note due from Sempra Energy which bears a variable interest rate based on short-term commercial paper rates. The balances of the note were $416 million and $268 million at December 31, 2002 and 2001, respectively, and were included in noncurrent assets under the caption "Due from unconsolidated affiliates". At December 31, 2001, PE had a promissory note due from Sempra Energy Global Enterprises (Global), which owns most of the businesses of Sempra Energy other than the California Utilities and serves a broad range of customers' energy needs. The note was $138 million at December 31, 2001 and was paid in full during 2002. PE also had $3 million due from other affiliates at both December 31, 2002 and 2001. In addition, PE had intercompany payables due to various affiliates of $96 million and $169 million at December 31, 2002, and 2001, respectively, which are reported as a current liability. These balances are due on demand. Of the total balances, $31 million and $27 million was recorded at SoCalGas at December 31, 2002 and 2001, respectively. New Accounting Standards SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143, issued in July 2001, addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. This applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal operation of long-lived assets, such as nuclear plants. It requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the liability is initially recorded, the entity increases the carrying amount of the related long-lived asset by the present value of the future retirement cost. Over time, the liability is accreted to its full value and paid, and the capitalized cost is depreciated over the useful life of the related asset. SFAS 143 is effective for financial statements issued for fiscal years beginning after June 15, 2002. As of January 1, 2003, the company had asset retirement obligations estimated to be $11 million associated with the retirement of the Montebello storage field. 37 SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets": In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS 144, which replaces SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS 144 applies to all long-lived assets, including discontinued operations. SFAS 144 requires that those long-lived assets classified as held for sale be measured at the lower of carrying amount (cost less accumulated depreciation) or fair value less cost to sell. Discontinued operations will no longer be measured at net realizable value or include amounts for operating losses that have not yet occurred. SFAS 144 also broadens the reporting of discontinued operations to include all components of an entity with operations that can be distinguished from the rest of the entity and that will be eliminated from the ongoing operations of the entity in a disposal transaction. The company has identified no material effects to the financial statements from the implementation of SFAS 144. SFAS 148, "Accounting for Stock-Based Compensation - Transition and Disclosure": In December 2002, the FASB issued SFAS 148, an amendment to SFAS 123, "Accounting for Stock-Based Compensation," which gives companies electing to expense employee stock options three methods to do so. In addition, the statement amends the disclosure requirements to require more prominent disclosure about the method of accounting for stock-based employee compensation and the effect of the method used on reported results in both annual and interim financial statements. The companies have elected to continue using the intrinsic value method of accounting for stock-based compensation. Therefore, the amendment to SFAS 123 will not have any effect on the companies' financial statements. See Note 6 for additional information regarding stock-based compensation. SFAS 149, "Accounting for Certain Financial Instruments with Characteristics of Liabilities and Equity": On January 22, 2003, the FASB directed its staff to prepare a draft of SFAS 149. The final draft is expected to be issued in March 2003. The statement will establish standards for accounting for financial instruments with characteristics of liabilities, equity, or both. Subsequent to the issuance of SFAS 149, certain investments that are currently classified as equity in the financial statements might have to be reclassified as liabilities. In addition, the FASB decided that SFAS 149 will prohibit the presentation of certain items in the mezzanine section (the portion of a balance sheet between liabilities and equity) of the statement of financial position. For example, certain mandatorily redeemable preferred stock, which is currently included in the mezzanine section, may be classified as a liability once SFAS 149 goes into effect. The proposed effective date of SFAS 149 is July 1, 2003 for the company. FASB Interpretation 45, "Guarantor's Accounting and Disclosure Requirements for Guarantees": In November 2002, the FASB issued Interpretation 45, which elaborates on the disclosures to be made in interim and annual financial statements of a guarantor about its obligations under certain guarantees that it has issued. It also clarifies that a guarantor is required to recognize, at the inception of a guarantee, a liability for the fair value of the obligation undertaken in issuing a guarantee. Initial recognition and measurement provisions of the Interpretation are applicable on a prospective basis to 38 guarantees issued or modified after December 31, 2002. The disclosure requirements are effective for financial statements of interim or annual periods ending after December 15, 2002. As of December 31, 2002, the company did not have any outstanding guarantees. Other Accounting Standards: During 2002 and 2001 the FASB and the Emerging Issues Task Force (EITF) issued several statements that are currently not applicable to the companies. In July 2001, the FASB issued SFAS 142, "Goodwill and Other Intangible Assets," which addresses how intangible assets that are acquired individually or with a group of other assets (but not those acquired in a business combination) should be accounted for in financial statements upon their acquisition. In April 2002, the FASB issued SFAS 145, which rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of Debt", and SFAS 64, "Extinguishments of Debt Made to Satisfy Sinking-Fund Requirements." In June 2002, the FASB issued SFAS 146, "Accounting for Costs Associated with Exit or Disposal Activities," which addresses accounting for restructuring and similar costs. SFAS 146 supersedes previous accounting guidance, principally EITF Issue 94-3, "Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring)." In October 2002, the FASB issued SFAS 147, "Accounting for Certain Financial Institutions - an amendment of SFAS 72 and 144 and FASB Interpretation 9," which applies to acquisitions of financial institutions. In June 2002, a consensus was reached in EITF Issue 02-3, which codifies and reconciles existing guidance on the recognition and reporting of gains and losses on energy trading contracts and addresses other aspects of the accounting for contracts involved in energy trading and risk management activities. In October 2002, the EITF reached a consensus to rescind EITF Issue 98-10, "Accounting for Energy Trading Contracts," the basis for mark-to-market accounting used for recording energy-trading activities. In January 2003, the FASB issued Interpretation 46, "Consolidation of Variable Interest Entities," which addresses consolidation by business enterprises of variable interest entities. NOTE 2. SHORT-TERM BORROWINGS At December 31, 2002, SoCalGas and its affiliate, SDG&E, had a combined revolving line of credit, under which each utility individually could borrow up to $300 million, subject to a combined borrowing limit for both utilities of $500 million. Borrowings under the agreement, which are available for general corporate purposes including support for commercial paper and variable-rate long-term debt, bear interest at rates varying with market rates and SoCalGas' credit rating. This revolving credit commitment expires in May 2003, at which time the outstanding borrowings may be converted into a one-year term loan subject to any requisite regulatory approvals related to long-term debt. This agreement requires SoCalGas to maintain a debt-to-total capitalization ratio (as defined in the agreement) of not to exceed 60 percent. The rights, obligations and covenants of each utility under the agreement are individual rather than joint with those of the other utility, and a default by one utility would not constitute a default by the other. These lines of credit were unused at December 31, 2002. At December 31, 2002, SoCalGas had no commercial paper outstanding. At December 31, 2002, PE had a $500 million two-year revolving line of credit, guaranteed by Sempra Energy, for the purpose of providing loans 39 to Global. The revolving credit commitment expires in April 2003, at which time the outstanding borrowings may be converted into a two-year term loan. Borrowings would be subject to mandatory repayment prior to the maturity date should PE's credit rating cease to be at least BBB- by Standard & Poor's (S&P) or SoCalGas' unsecured long-term credit ratings cease to be at least BBB by S&P and Baa2 by Moody's Investor Services, Inc. (Moody's), should Sempra Energy's or SoCalGas' debt-to-total capitalization ratio (as defined in the agreement) exceed 65 percent, or should there be a change in law materially and adversely affecting the ability of SoCalGas to pay dividends or make distributions to PE. Borrowings bear interest at rates varying with market rates and the amount of outstanding borrowings. PE's line of credit was unused at December 31, 2002 and December 31, 2001. NOTE 3. LONG-TERM DEBT - -------------------------------------------------------------- December 31, (Dollars in millions) 2002 2001 - -------------------------------------------------------------- First-mortgage bonds 5.75% November 15, 2003 $ 100 $ 100 4.8% October 1, 2012 250 -- 7.375% March 1, 2023 100 100 7.5% June 15, 2023 125 125 6.875% November 1, 2025 175 175 6.875% August 15, 2002 -- 100 ----------------------- 750 600 ----------------------- Unsecured long-term debt 5.67% January 15, 2003 75 75 6.375% May 14, 2006 8 8 ----------------------- 83 83 ----------------------- 833 683 Less: Current portion of long-term debt 175 100 Market value adjustment on interest-rate swap -- 4 Unamortized discount on long-term debt 1 -- ----------------------- Total $ 657 $ 579 - -------------------------------------------------------------- Maturities of long-term debt are $175 million in 2003, $8 million in 2006, and $650 million thereafter. First-mortgage Bonds The first-mortgage bonds are secured by a lien on SoCalGas' utility plant. SoCalGas may issue additional first-mortgage bonds upon compliance with the provisions of its bond indentures, which require, among other things, the satisfaction of pro forma earnings-coverage tests on first-mortgage bond interest and the availability of sufficient mortgaged property to support the additional bonds. The most restrictive of these tests (the property test) would permit the issuance, subject to 40 CPUC authorization, of an additional $624 million of first-mortgage bonds at December 31, 2002. In November 2001, SoCalGas called its $150 million 8.75% first-mortgage bonds at a premium of 3.59 percent. On December 11, 2001, SoCalGas entered into an interest-rate swap which effectively exchanged the fixed rate on its $175 million 6.875% first-mortgage bonds for a floating rate. On September 30, 2002, SoCalGas terminated the swap, receiving cash proceeds of $10 million, comprised of $4 million in accrued interest and a $6 million amortizable gain. Additional information is provided under "Interest-Rate Swaps" below. In August 2002, SoCalGas paid off its $100 million 6.875% first-mortgage bonds. In October 2002, SoCalGas publicly offered and sold $250 million of 4.8% first-mortgage bonds, maturing on October 1, 2012. The bonds are not subject to a sinking fund and are not redeemable prior to maturity except through a make-whole mechanism. Proceeds from the bond sale have become part of the company's general funds to replenish amounts previously expended to refund and retire indebtedness, and for working capital and other general corporate purposes. These bonds were assigned ratings of A+ by the S&P rating agency, A1 by Moody's, and AA by Fitch, Inc. Callable Bonds At SoCalGas' option, certain fixed-rate bonds may be called at a premium, including $400 million in 2003. Of SoCalGas' remaining callable bonds, $8 million are callable in 2006. Unsecured Long-term Debt Various long-term obligations totaling $83 million are unsecured at December 31, 2002. In October 2001, SoCalGas repaid $120 million of 6.38% medium-term notes upon maturity. In July 2000, SoCalGas repaid $30 million of 8.75% medium-term notes upon maturity. On January 15, 2003, $70 million of SoCalGas' 5.67% $75 million medium- term notes were put back to the company. The remaining $5 million matures on January 18, 2028. Interest-Rate Swaps The company periodically enters into interest-rate swap agreements to moderate its exposure to interest-rate changes and to lower its overall cost of borrowing. On December 11, 2001, SoCalGas executed a cancelable- call interest-rate swap, exchanging its fixed-rate obligation of 6.875% on its $175 million first-mortgage bonds for a floating rate of LIBOR plus 4 basis points. On September 30, 2002, SoCalGas terminated the swap, receiving cash proceeds of $10 million, comprised of $4 million in accrued interest and a $6 million amortizable gain. The company believes the remaining swap is fully effective in its purpose of converting the underlying debt's fixed rate to a floating rate and meets the criteria for accounting under the short-cut method defined in SFAS 133 for fair value hedges of debt instruments. Accordingly, market value adjustments to long-term debt of $4 million and ($4) million were recorded at December 31, 2002 and 2001, respectively, to reflect, without affecting net income or other comprehensive income, the favorable/unfavorable economic consequences (as measured at December 31, 41 2002 and 2001) of having entered into the swap transactions. See additional discussion of interest-rate swaps in Note 7. Financial Covenants SoCalGas' first-mortgage bond indentures require the satisfaction of certain bond interest coverage ratios and the availability of sufficient mortgaged property to issue additional first-mortgage bonds, but do not restrict other indebtedness. Note 2 discusses the financial covenants applicable to short-term debt. NOTE 4. INCOME TAXES The reconciliation of the statutory federal income tax rate to the effective income tax rate is as follows: Years ended December 31 2002 2001 2000 - --------------------------------------------------------------------- Statutory federal income tax rate 35.0% 35.0% 35.0% Depreciation 5.2 5.4 5.2 State income taxes - net of federal income tax benefit 5.4 6.9 6.9 Tax credits (0.8) (0.8) (0.7) Other - net (0.4) (1.1) 0.3 ------------------------ Effective income tax rate 44.4% 45.4% 46.7% - --------------------------------------------------------------------- The components of income tax expense are as follows: (Dollars in millions) 2002 2001 2000 - --------------------------------------------------------------------- Current: Federal $ 94 $ 116 $ 139 State 29 30 41 ------------------------ Total 123 146 180 ------------------------ Deferred: Federal 45 20 7 State 5 8 -- ------------------------ Total 50 28 7 ------------------------ Deferred investment tax credits - net (3) (3) (2) ------------------------ Total income tax expense $ 170 $ 171 $ 185 - --------------------------------------------------------------------- Federal and state income taxes are allocated between operating income and other income. PE is included in the consolidated income tax return of Sempra Energy and is allocated income tax expense from Sempra Energy in an amount equal to that which would result from having always filed a separate return. 42 Accumulated deferred income taxes at December 31 consist of the following: (Dollars in millions) 2002 2001 - --------------------------------------------------------------------- Deferred Tax Liabilities: Differences in financial and tax bases of utility plant $ 290 $ 295 Regulatory balancing accounts 54 56 Regulatory assets 32 36 Other 53 49 -------------------- Total deferred tax liabilities 429 436 -------------------- Deferred Tax Assets: Investment tax credits 32 34 Postretirement benefits 32 36 Other deferred liabilities 157 174 Restructuring costs 42 42 Other 45 73 -------------------- Total deferred tax assets 308 359 -------------------- Net deferred income tax liability $ 121 $ 77 - --------------------------------------------------------------------- The net deferred income tax liability is recorded on the Consolidated Balance Sheets at December 31 as follows: (Dollars in millions) 2002 2001 - ---------------------------------------------------------------------- Current asset $ (55) $ (33) Noncurrent liability 176 110 -------------------- Total $ 121 $ 77 - ---------------------------------------------------------------------- NOTE 5. EMPLOYEE BENEFIT PLANS Pension and Other Postretirement Benefits The company sponsors several qualified and nonqualified pension plans and other postretirement benefit plans for its employees. During 2002, the company had amendments reflecting retiree cost of living adjustments which resulted in an increase in the pension plan benefit obligation of $48 million. During 2000, the company participated in a voluntary separation program. As a result, the company recorded a $40 million special termination benefit. 43 The following tables provide a reconciliation of the changes in the plans' projected benefit obligations and the fair value of assets over the two years, and a statement of the funded status as of each year end:
Other Pension Benefits Postretirement Benefits -------------------------------------------- (Dollars in millions) 2002 2001 2002 2001 - ----------------------------------------------------------------------------------------- WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31: Discount rate 6.50% 7.25% 6.50% 7.25% Expected return on plan assets 8.00% 8.00% 8.00% 8.00% Rate of compensation increase 4.50% 5.00% 4.50% 5.00% Cost trend of covered health-care charges -- -- 7.00%(1) 7.25%(1) CHANGE IN PROJECTED BENEFIT OBLIGATION: Net obligation at January 1 $1,111 $1,125 $ 457 $ 415 Service cost 27 25 10 9 Interest cost 86 78 35 32 Plan amendments 48 -- -- -- Actuarial (gain) loss 98 (46) 177 23 Transfer of liability (2) 91 -- 30 -- Benefits paid (93) (71) (27) (22) -------------------------------------------- Net obligation at December 31 1,368 1,111 682 457 -------------------------------------------- CHANGE IN PLAN ASSETS: Fair value of plan assets at January 1 1,452 1,682 392 434 Actual return on plan assets (168) (162) (44) (33) Employer contributions 1 -- 17 13 Transfer of assets (2) 97 3 30 -- Other -- -- 2 -- Benefits paid (93) (71) (27) (22) -------------------------------------------- Fair value of plan assets at December 31 1,289 1,452 370 392 -------------------------------------------- Plan assets net of benefit obligation at December 31 (79) 341 (312) (65) Unrecognized net actuarial (gain) loss 82 (322) 235 (23) Unrecognized prior service cost 78 35 -- -- Unrecognized net transition obligation 1 2 -- -- -------------------------------------------- Net recorded asset (liability) at December 31 $ 82 $ 56 $ (77) $ (88) - ----------------------------------------------------------------------------------------- (1) Decreasing to ultimate trend of 6.50% in 2004. (2) To reflect transfer of plan assets and liability from Sempra Energy. The following table provides the amounts recognized on the Consolidated Balance Sheets (under noncurrent sundry assets and postretirement benefits other than pensions) at December 31: Other Pension Benefits Postretirement Benefits ------------------------------------------- (Dollars in millions) 2002 2001 2002 2001 - ----------------------------------------------------------------------------------------- Prepaid benefit cost $ 93 $ 67 $ -- -- Accrued benefit cost (11) (11) (77) $ (88) Additional minimum liability -- (2) -- -- Intangible asset -- 1 -- -- Accumulated other comprehensive income, pretax -- 1 -- -- ------------------------------------------- Net recorded asset (liability) $ 82 $ 56 $ (77) $ (88) - -----------------------------------------------------------------------------------------
44 The following table provides the components of net periodic benefit cost for the plans:
Other (Dollars in millions) Pension Benefits Postretirement Benefits -------------------------------------------------- Years ended December 31 2002 2001 2000 2002 2001 2000 - ----------------------------------------------------------------------------------------- Service cost $ 27 $ 25 $ 23 $ 10 $ 9 $ 8 Interest cost 86 78 84 35 32 28 Expected return on assets (130) (129) (131) (35) (34) (32) Amortization of: Transition obligation 1 1 1 8 8 9 Prior service cost 4 3 4 -- -- -- Actuarial gain (19) (28) (29) -- (3) (8) Special termination benefits -- -- 33 -- -- 7 Regulatory adjustment 32 51 18 24 29 28 -------------------------------------------------- Total net periodic benefit cost $ 1 $ 1 $ 3 $ 42 $ 41 $ 40 - -----------------------------------------------------------------------------------------
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 $ 8 $ (6) Effect on the health-care component of the accumulated other postretirement benefit obligation $111 $(89) - ---------------------------------------------------------------------- Other postretirement benefits include retiree life insurance, medical benefits for retirees and their spouses, and Medicare Part B reimbursement for certain retirees. Savings Plans The company offers savings plans, administered by plan trustees, to all eligible employees. Eligibility to participate in the plans is immediate for salary deferrals. Employees may contribute, subject to plan provisions, from one percent to 25 percent of their regular earnings. After one year of completed service, the company begins to make matching contributions. Employer contributions are equal to 50 percent of the first 6 percent of eligible base salary contributed by employees and, if certain company goals are met, an additional amount related to incentive compensation payments. Employer contributions are invested in Sempra Energy common stock and must remain so invested until termination of employment. At the direction of the employees, the employees' contributions are invested in Sempra Energy stock, mutual funds, or institutional trusts. Employer contributions for the SoCalGas plans are partially funded by the Sempra Energy employee stock ownership plan and Trust. Company contributions to the savings plans were $8 million in 2002, $7 million in 2001 and $5 million in 2000. 45 NOTE 6. STOCK-BASED COMPENSATION Sempra Energy has stock-based compensation plans intended to align employee and shareholder objectives related to the long-term growth of the company. The plans permit a wide variety of stock-based awards, including nonqualified stock options, incentive stock options, restricted stock, stock appreciation rights, performance awards, stock payments and dividend equivalents. In 1995, SFAS 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 123, Sempra Energy and its subsidiaries adopted only its disclosure requirements and continue to account for stock-based compensation in accordance with the provisions of Accounting Principles Board Opinion 25, "Accounting for Stock Issued to Employees." See additional discussion of SFAS 148, the amendment to SFAS 123, in Note 1. The subsidiaries record an expense for the plans to the extent that subsidiary employees participate in the plans, or that subsidiaries are allocated a portion of Sempra Energy's costs of the plans. PE recorded expenses of $1 million, $3 million and $2 million in 2002, 2001 and 2000, respectively. NOTE 7. FINANCIAL INSTRUMENTS Fair Value The fair values of certain of the company's financial instruments (cash, temporary investments, notes receivable, dividends payable, short-term debt and customer deposits) approximate the carrying amounts. The following table provides the carrying amounts and fair values of the remaining financial instruments at December 31:
(Dollars in millions) 2002 2001 - ------------------------------------------------------------------------------- Carrying Fair Carrying Fair Amount Value Amount Value - ------------------------------------------------------------------------------- First-mortgage bonds $ 750 $ 763 $ 600 $ 594 Other long-term debt 83 76 83 88 ------ ------ ------ ------ Total long-term debt $ 833 $ 839 $ 683 $ 682 - ------------------------------------------------------------------------------- PE: Preferred stock $ 80 $ 53 $ 80 $ 47 Preferred stock of subsidiary 20 17 20 17 ------ ------ ------ ------ $ 100 $ 70 $ 100 $ 64 - ------------------------------------------------------------------------------- SoCalGas: Preferred stock $ 22 $ 18 $ 22 $ 18 - -------------------------------------------------------------------------------
The fair values of long-term debt and preferred stock were estimated based on quoted market prices for them or for similar issues. 46 Accounting for Derivative Instruments and Hedging Activities SFAS 133 "Accounting for Derivative Instruments and Hedging Activities," as amended by SFAS 138, "Accounting for Certain Derivative Instruments and Certain Hedging Activities" recognizes all derivatives as either assets or liabilities in the statement of financial position, measures those instruments at fair value and recognizes 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 exposure. The company utilizes derivative financial instruments to reduce its exposure to unfavorable changes in commodity prices, which are subject to significant and often volatile fluctuation. Derivative financial instruments include futures, forwards, swaps, options and long-term delivery contracts. These contracts allow the company to predict with greater certainty the effective prices to be received by the company and the prices to be charged to its customers. Since adoption of SFAS 133 on January 1, 2001, the company classifies its forward contracts as follows: Normal Purchase and Sales: These contracts generally are long-term contracts that are settled by physical delivery and, therefore, are eligible for the normal purchases and sales exception of SFAS 133. The contracts are accounted for at historical cost with gains and losses reflected in the Statements of Consolidated Income at the contract settlement date. Natural Gas Purchases and Sales: The unrealized gains and losses related to these forward contracts are reflected on the Consolidated Balance Sheets as regulatory assets and liabilities to the extent derivative gains and losses will be recoverable or payable in future rates. If gains and losses are not recoverable or payable through future rates, the company applies hedge accounting if certain criteria are met. When a contract no longer meets the requirements of SFAS 133, the unrealized gains and losses will be amortized over the remaining contract life. In instances where hedge accounting is applied to derivatives, cash flow hedge accounting is elected and, accordingly, changes in fair values of the derivatives are included in other comprehensive income, but not reflected in the Statements of Consolidated Income until the corresponding hedged transaction is settled. The effect on other comprehensive income for the years ended December 31, 2002 and 2001 was not material. In instances where derivatives do not qualify for hedge accounting, gains and losses are recorded in the Statements of Consolidated Income. 47 The following were recorded in the Consolidated Balance Sheets at December 31: (Dollars in millions) 2002 2001 - ----------------------------------------------------------------------- Fixed-priced contracts and other derivatives: Current assets $ - $ 59 Noncurrent assets - 1 ----- ----- Total - 60 ----- ----- Current liabilities 96 85 Noncurrent liabilities 233 154 ----- ----- Total 329 239 Other comprehensive income - 1 ----- ----- Net liabilities and equity $ 329 $ 180 ===== ===== Regulatory assets and liabilities: Current regulatory assets 92 85 Noncurrent regulatory assets 233 150 ----- ----- Total 325 235 ----- ----- Regulatory balancing account liabilities - 50 Current regulatory liabilities - 3 ----- ----- Total - 53 ----- ----- Net regulatory assets $ 325 $ 182 ===== ===== - ----------------------------------------------------------------------- $3 million of losses in 2002 and $3 million of income in 2001 were recorded in operating revenues in the Statements of Consolidated Income. Additionally, a market value adjustment of $4 million was made at December 31, 2001 to long-term debt relating to a fixed-to-floating interest rate swap agreement discussed below. This market value adjustment was subsequently reversed at September 30, 2002 upon cancellation of the swap agreement. Market Risk The company's policy is to use derivative instruments to manage exposure to fluctuations in interest rates, foreign-currency exchange rates and prices. Transactions involving these instruments are with major exchanges and other firms believed to be credit-worthy. The use of these instruments exposes the company to market and credit risk which may at times be concentrated with certain counterparties, although counterparty nonperformance is not anticipated. Interest-Rate Risk Management The company periodically enters into interest-rate swap agreements to moderate exposure to interest-rate changes and to lower the overall cost of borrowing. 48 SoCalGas had an agreement, which was a cancelable-call interest-rate swap, exchanging its fixed-rate obligation of 6.875% on its $175 million first-mortgage bonds for a floating rate of LIBOR plus four basis points. On September 30, 2002, SoCalGas terminated the swap, receiving cash proceeds of $10 million, comprised of $4 million in accrued interest and a $6 million amortizable gain. The company believes both swaps have been fully effective in their purpose of converting the fixed rate stated in the debt to a floating rate and the swaps meet the criteria for accounting under the short-cut method defined in SFAS 133 for fair value hedges of debt instruments. Accordingly, market value adjustments of $20 million and $22 million (as discussed above) were added to long-term debt during the years ended December 31, 2002 and 2001, respectively, and no net gains or losses were recorded in income in respect to these swaps. Energy Derivatives SoCalGas utilizes derivative instruments to reduce its exposure to unfavorable changes in energy prices, which are subject to significant and often volatile fluctuation. Derivative instruments are comprised of futures, forwards, swaps, options and long-term delivery contracts. These contracts allow SoCalGas to predict with greater certainty the effective prices to be received and the prices to be charged to their customers. See Note 1 for discussion of how these derivatives are classified under SFAS 133. Energy Contracts SoCalGas records natural gas contracts in "Cost of natural gas distributed" in the Statements of Consolidated Income. For open contracts not expected to result in physical delivery, changes in market value of the contracts are recorded in these accounts during the period the contracts are open, with an offsetting entry to a regulatory asset or liability. The majority of the company's contracts result in physical delivery. NOTE 8. PREFERRED STOCK Preferred Stock Of Southern California Gas Company - ----------------------------------------------------------------- December 31, (Dollars in millions) 2002 2001 - ----------------------------------------------------------------- $25 par value, authorized 1,000,000 shares 6% Series, 28,041 shares outstanding $ 1 $ 1 6% Series A, 783,032 shares outstanding 19 19 Without par value, authorized 10,000,000 shares -- -- -------------- $20 $20 - ---------------------------------------------------------------- None of SoCalGas' preferred stock is callable. All series have one vote per share and cumulative preferences as to dividends, and have a liquidation value of $25 per share plus any unpaid dividends. In addition, the 6% Series preferred stock would also share pro rata with common stock in the remaining assets. 49 Preferred Stock Of Pacific Enterprises - -------------------------------------------------------------------------- December 31, (Dollars in millions, except call price) Call Price 2002 2001 - -------------------------------------------------------------------------- $4.75 Dividend, 200,000 shares outstanding $100.00 $ 20 $ 20 $4.50 Dividend, 300,000 shares outstanding $100.00 30 30 $4.40 Dividend, 100,000 shares outstanding $101.50 10 10 $4.36 Dividend, 200,000 shares outstanding $101.00 20 20 $4.75 Dividend, 253 shares outstanding $101.00 -- -- ------------------ Total preferred stock $ 80 $ 80 - -------------------------------------------------------------------------- PE is authorized to issue 15,000,000 shares of preferred stock without par value. The preferred stock is subject to redemption at PE's option at any time upon not less than 30 days' notice, at the applicable redemption price for each series, together with unpaid dividends. All series have one vote per share and cumulative preferences as to dividends, and have a liquidation value of $100 per share plus any unpaid dividends. NOTE 9. REGULATORY MATTERS Gas Industry Restructuring 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. In July 1999, after hearings, the CPUC issued a decision stating which natural gas regulatory changes it found most promising, encouraging parties to submit settlements addressing those changes, and providing for further hearings if necessary. On December 11, 2001, the CPUC issued a decision adopting much of a settlement that had been submitted in 2000 by SoCalGas and approximately 30 other parties representing all segments of the natural gas industry in Southern California, but opposed by some parties. The CPUC decision adopts the following provisions: a system for shippers to hold firm, tradable rights to capacity on SoCalGas' major natural gas transmission lines, with SoCalGas' shareholders at risk for whether market demand for these rights will cover the cost of these facilities; a further unbundling of SoCalGas' storage services, giving SoCalGas greater upward pricing flexibility (except for storage service for core customers) but with increased shareholder risk for whether market demand will cover storage costs; new balancing services, including separate core and noncore balancing provisions; a reallocation among customer classes of the cost of interstate pipeline capacity held by SoCalGas and an unbundling of interstate capacity for natural gas marketers serving core customers; and the elimination of noncore customers' option to obtain natural gas procurement service from SoCalGas. The CPUC modified the settlement to provide increased protection against the exercise of market power by persons who would acquire rights on the SoCalGas natural gas transmission system. The CPUC also rejected certain aspects of the settlement that would have provided more options for natural gas marketers serving core customers. During 2002 the company filed a proposed implementation schedule and revised tariffs and rules required for implementation. However, protests 50 of these compliance filings were filed, and the CPUC has not yet authorized implementation of most of the provisions of its decision. On December 30, 2002, the CPUC deferred acting on a plan to implement its decision. SoCalGas believes that implementation of the decision would make natural gas service more reliable, more efficient and better tailored to meet the needs of customers. The decision is not expected to adversely affect SoCalGas' earnings. Cost of Service (COS) and Performance-Based Regulation (PBR) To promote efficient operations and improved productivity and to move away from reasonableness reviews and disallowances, the CPUC adopted PBR for SoCalGas effective in 1997. PBR has resulted in modification to the general rate case and certain other regulatory proceedings for SoCalGas. Under PBR, regulators require future income potential to be tied to achieving or exceeding specific performance and productivity goals, rather than relying solely on expanding utility plant to increase earnings. The three areas that are eligible for PBR rewards are operational incentives based on measurements of safety, reliability and customer satisfaction; demand-side management (DSM) rewards based on the effectiveness of the programs; and natural gas procurement rewards. These incentive rewards are not included in the company's earnings before they are approved by the CPUC. The COS and PBR cases for SoCalGas were filed on December 20, 2002. The filings outline projected expenses (excluding the commodity cost of natural gas consumed by customers or expenses for programs such as low- income assistance) and revenue requirements for 2004 and a formula for 2005 through 2008. SoCalGas' cost of service study proposes an increase in natural gas base rate revenues of $130 million. The filings also requested a continuance and expansion of PBR in terms of earnings sharing and performance service standards that include both reward and penalty provisions related to customer satisfaction, employee safety and system reliability. The resulting new base rates are expected to be effective on January 1, 2004. A CPUC decision is expected in late 2003. SoCalGas' PBR mechanism is in effect through December 31, 2003, at which time the mechanism will be updated. That update will include, among other things, a reexamination of SoCalGas' reasonable costs of operation to be allowed in rates. An October 10, 2001 decision denied SoCalGas' request to continue equal sharing between ratepayers and shareholders of the estimated savings for the PE/Enova merger as more fully discussed in Note 1 and, instead, ordered that all of the estimated 2003 merger savings go to ratepayers. This decision will adversely affect the company's 2003 net income by $24 million. On January 16, 2003, the CPUC issued a resolution approving SoCalGas' report on its PBR results for 2000. The resolution approved SoCalGas' calculation of the amount that should be retained by shareholders. The resolution also approved SoCalGas' request for an $80,000 reward for employee safety results. SoCalGas is not eligible for any other rewards and was not found by the resolution to owe any penalties. During 2002, SoCalGas filed its 2001 PBR report with the CPUC. Based on the results against the performance indicator benchmarks, SoCalGas requested a total net reward of $0.5 million. 51 Gas Cost Incentive Mechanism (GCIM) SoCalGas' GCIM allows SoCalGas to receive a share of the savings it achieves by buying natural gas for customers below monthly benchmarks. 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 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 to mitigate risk and better manage natural gas costs. On December 17, 2002, the CPUC issued its final decision in the GCIM Year 6 Phase 2 proceeding, approving, with modifications, a settlement agreement among SoCalGas, the CPUC's ORA and The Utility Reform Network, a consumer-advocacy group, and extending the GCIM mechanism to Year 7 and beyond. SoCalGas has requested that the CPUC approve rewards of $30.8 million and $17.4 million for GCIM Years 7 and 8, respectively. CPUC approval of these rewards is expected in 2003, subject to possible future adjustment as a result of its investigation into the run-up in California border natural gas prices during the winter of 2000-2001 (discussed below). In the past, shareholder rewards associated with the GCIM had been recorded to SoCalGas' Purchased Gas Balancing Account after the close of the GCIM period, covering the utility's natural gas supply operations for the twelve months ended March 31. In June 2002, the CPUC issued a decision allowing SoCalGas to recover its GCIM earnings through its monthly core procurement filing beginning January 1, 2003. These awards are not included in SoCalGas' earnings until approved by the CPUC. Demand Side Management (DSM) and Energy Efficiency Awards Since the 1990s, the investor-owned utilities (IOUs) have been eligible to earn awards for implementing and/or administering energy-conservation programs. SoCalGas has offered these programs to customers and has consistently achieved significant earnings therefrom. Beginning in 2002, earnings for non-low-income energy-efficiency programs were eliminated; however, awards related to DSM and low-income energy-efficiency programs may still be requested. SoCalGas has outstanding before the CPUC applications to recover shareholder rewards earned for performance under the DSM programs for 1995 through 2001. Reward requests in these applications total $9.1 million. A CPUC Administrative Law Judge has scheduled a pre-hearing conference to review the IOUs' DSM programs. The review may include reanalyzing the uncollected portion of past rewards earned by IOUs (which have not been included in SoCalGas' income), and potentially recompute the amount of the DSM rewards. The company has opposed such a recalculation. The issue is still pending before the CPUC. 52 Pending Incentive Awards At December 31, 2002, the following performance incentives were pending CPUC approval and, therefore, were not included in the company's earnings (dollars in millions): Program --------------------------- PBR $ 0.5 GCIM 48.2 DSM 9.1 --------------------------- Total $ 57.8 =========================== Cost of Capital Effective January 1, 2003, SoCalGas' authorized rate of return on common equity (ROE) is 10.82 percent and its return on ratebase (ROR) is 8.68 percent. These rates will continue to be effective until the next periodic review by the CPUC unless market interest-rate changes are large enough to trigger an automatic adjustment prior thereto, which last occurred in October 2002 and adjusted rates downward from the previous 11.6 percent (ROE) and 9.49 percent (ROR) to the current levels. This change results in an annual revenue requirement decrease of $10.5 million. Border Price Investigation On November 21, 2002, the CPUC instituted an investigation into the Southern California natural gas market and the price of natural gas delivered to the California-Arizona (CA-AZ) border during the period of March 2000 through May 2001. The CPUC intends to examine the possible reasons for and issues potentially related to the elevated border prices that affected California consumers during this period. SoCalGas is included among the respondents to the investigation. If the investigation determines that the conduct of any respondent contributed to the natural gas price spikes at the CA-AZ border during this period, the CPUC may modify the respondent's applicable natural gas procurement incentive mechanism, reduce the amount of any shareholder award for the period involved, or order the respondent to issue a refund to ratepayers to offset the higher rates paid. SoCalGas is fully cooperating with the CPUC in the investigation and believe that the CPUC will ultimately determine that the company was not responsible for the high border prices during this period. Biennial Cost Allocation Proceeding (BCAP) The BCAP determines the allocation of authorized costs between customer classes and the rates and rate design applicable to such classes for natural gas transportation service. The BCAP adjusts SoCalGas' rates to reflect variances in customer demand as compared to the adopted forecasts previously used in establishing customer natural gas transportation rates. The mechanism in effect through the end of 2002 largely eliminated the effect on SoCalGas' income of variances in customer demand and natural gas transportation costs. SoCalGas filed its 2003 BCAP on September 21, 2001. In February 2003, a CPUC Administrative Law Judge granted a motion to defer the BCAP. SoCalGas must submit an 53 amended application by September 2003, with new rates scheduled to be implemented by September 2004. On December 5, 2002, the CPUC issued a decision approving 100 percent balancing account protection for all core and noncore transportation costs, effective in 2003. Utility Integration On September 20, 2001, the CPUC approved Sempra Energy's request to integrate the management teams of SoCalGas and SDG&E. The decision retains the separate identities of each utility and is not a merger. Instead, utility integration is a reorganization that consolidates senior management functions of the two utilities and returns to the utilities the majority of shared support services previously provided by Sempra Energy's centralized corporate center. Once implementation is completed, the integration is expected to result in more effective operations. In a related development, an August 2002 CPUC interim decision denied a request by SoCalGas and SDG&E to combine their natural gas procurement activities at this time, pending completion of the CPUC's Border Price Investigation referred to above. CPUC Investigation of Energy-Utility Holding Companies The CPUC has initiated an investigation into the relationship between California's IOUs and their parent holding companies. Among the matters to be considered in the investigation are utility dividend policies and practices and obligations of the holding companies to provide financial support for utility operations under the agreements with the CPUC permitting the formation of the holding companies. On January 11, 2002, the CPUC issued a decision to clarify under what circumstances, if any, a holding company would be required to provide financial support to its utility subsidiaries. The CPUC broadly determined that it would require the holding company to provide cash to a utility subsidiary to cover its operating expenses and working capital to the extent they are not adequately funded through retail rates. This would be in addition to the requirement of holding companies to cover their utility subsidiaries' capital requirements, as the IOUs have previously acknowledged in connection with the holding companies' formations. On January 14, 2002, the CPUC ruled on jurisdictional issues, deciding that the CPUC had jurisdiction to create the holding company system and, therefore, retains jurisdiction to enforce conditions to which the holding companies had agreed. The company's request for rehearing on the issues was denied by the CPUC and the company subsequently filed appeals in the California Court of Appeal, which are still pending. NOTE 10. COMMITMENTS AND CONTINGENCIES Natural Gas Contracts SoCalGas buys natural gas under short-term and long-term contracts. Short-term purchases are from various suppliers and are primarily based on monthly spot-market prices. SoCalGas transports natural gas under long-term firm pipeline capacity agreements that provide for annual reservation charges, which are recovered in rates. SoCalGas has commitments for firm pipeline capacity under contracts with pipeline companies that expire at various dates through 2006. 54 At December 31, 2002, the future minimum payments under natural gas contracts were: Natural (Dollars in millions) Transportation Gas Total - ------------------------------------------------------------------------ 2003 $ 197 $ 642 $ 839 2004 199 3 202 2005 190 3 193 2006 104 2 106 2007 2 2 4 Thereafter -- -- -- -------------------------------------------- Total minimum payments $ 692 $ 652 $1,344 - ------------------------------------------------------------------------ Total payments under natural gas contracts were $1.2 billion in 2002, $2.1 billion in 2001, and $1.4 billion in 2000. Leases PE and SoCalGas have operating leases on real and personal property expiring at various dates from 2003 to 2030. Certain leases on office facilities contain escalation clauses requiring annual increases in rent ranging from 4 percent to 7 percent. The rentals payable under these leases are determined on both fixed and percentage bases, and most leases contain extension options which are exercisable by PE or SoCalGas. At December 31, 2002, the minimum rental commitments payable in future years under all noncancellable leases were as follows: - ----------------------------------------------------------------- (Dollars in millions) PE SoCalGas - ----------------------------------------------------------------- 2003 $ 54 $ 41 2004 53 40 2005 52 39 2006 52 39 2007 54 41 Thereafter 189 154 --------------------- Total future rental commitments $ 454 $ 354 - ----------------------------------------------------------------- In connection with the quasi-reorganization described in Note 1, PE recorded liabilities of $102 million to adjust to fair value the operating leases related to its headquarters and other facilities at December 31, 1992. The remaining amount of these liabilities was $42 million at December 31, 2002. These leases are included in the above table. Rent expense for operating leases totaled $54 million in 2002, $51 million in 2001 and $55 million in 2000, which included rent expense for SoCalGas of $42 million, $39 million, and $41 million, respectively. 55 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. As applicable, appropriate and relevant, these laws and regulations require that the company investigate and remediate the effects of the release or disposal of materials at sites associated with past and present operations, including sites at which the company has been identified as a Potentially Responsible Party (PRP) under the federal Superfund laws and comparable state laws. Costs incurred to operate the facilities in compliance with these laws and regulations generally have been recovered in customer rates. Significant costs incurred to mitigate or prevent future environmental contamination or extend the life, increase the capacity or improve the safety or efficiency of property utilized in current operations are capitalized. The company's capital expenditures to comply with environmental laws and regulations were $4 million in 2002, $4 million in 2001 and $1 million in 2000. The cost of compliance with these regulations over the next five years is not expected to be significant. Costs that relate to current operations or an existing condition caused by past operations are generally recorded as a regulatory asset due to the assurance that these costs will be recovered in rates. The environmental issues currently facing the company or resolved during the latest three-year period include investigation and remediation of its manufactured-gas sites (22 completed as of December 31, 2002 and 20 to be completed), and cleanup of third-party waste-disposal sites used by the company, which has been identified as a PRP (investigations and remediations are continuing). Environmental liabilities are recorded when the company's liability is probable and the costs are reasonably estimable. In many cases, however, investigations are not yet at a stage where the company has been able to determine whether it is liable or, if the liability is probable, to reasonably estimate the amount or range of amounts of the cost or certain components thereof. Estimates of the company's liability are further subject to other uncertainties, such as the nature and extent of site contamination, evolving remediation standards and imprecise engineering evaluations. The accruals are reviewed periodically and, as investigations and remediation proceed, adjustments are made as necessary. At December 31, 2002, the company's accrued liability for environmental matters was $42.6 million, of which $41.2 million related to manufactured-gas sites, $1.0 million to waste-disposal sites used by the company (which has been identified as a PRP) and $0.4 million to other hazardous waste sites. The accruals for the manufactured-gas and waste-disposal sites are expected to be paid ratably over the next four years. Litigation Lawsuits filed in 2000 and currently consolidated in San Diego Superior Court seek class-action certification and damages, alleging that Sempra Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. and several of its affiliates, unlawfully sought to control and have manipulated natural gas and electricity markets. On October 16, 2002, the assigned San Diego Superior Court judge ruled that the case can proceed with 56 discovery and that the California courts, rather than the FERC, have jurisdiction in the case. This was a preliminary ruling and not a ruling on the merits or facts of the case. Northern California cases, which only name El Paso as a defendant, are scheduled for trial in September 2003 and the remainder of the cases is set for trial in January 2004. During the fourth quarter of 2002, additional similar lawsuits have been filed in various jurisdictions. Management believes the allegations are without merit. In response to an inquiry by FERC regarding natural gas trading, SoCalGas has denied engaging in "wash" or "round trip" trading transactions. It is also cooperating with the FERC and other governmental agencies and officials in their various investigations of the California energy markets. Except for the matters referred to above, neither the company 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. Management believes that these matters will not have a material adverse effect on the company's financial condition or results of operations. Concentration Of Credit Risk The company maintains credit policies and systems to manage overall credit risk. These policies include 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. SoCalGas grants credit to customers and counterparties, substantially all of whom are located in its service territories, which cover most of Southern California and a portion of central California. 57 NOTE 11. QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarters ended ------------------------------------------------ (Dollars in millions) March 31 June 30 September 30 December 31 - -------------------------------------------------------------------------------------- 2002 Operating revenues $ 722 $ 680 $ 597 $ 859 Operating expenses 657 622 534 799 ------------------------------------------------ Operating income $ 65 $ 58 $ 63 $ 60 ------------------------------------------------ Net income $ 59 $ 50 $ 55 $ 49 Dividends on preferred stock 1 1 1 1 ------------------------------------------------ Earnings applicable to common shares $ 58 $ 49 $ 54 $ 48 ================================================ 2001 Operating revenues $ 1,548 $ 927 $ 561 $ 684 Operating expenses 1,480 864 489 613 ------------------------------------------------ Operating income $ 68 $ 63 $ 72 $ 71 ------------------------------------------------ Net income $ 50 $ 49 $ 57 $ 50 Dividends on preferred stock 1 1 1 1 ------------------------------------------------ Earnings applicable to common shares $ 49 $ 48 $ 56 $ 49 ================================================
The sum of the quarterly amounts does not necessarily equal the annual totals due to rounding. 58 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA -- Southern California Gas Company INDEPENDENT AUDITORS' REPORT To the Board of Directors and Shareholders of Southern California Gas Company: We have audited the accompanying consolidated balance sheets of Southern California Gas Company and subsidiaries (the "Company") as of December 31, 2002 and 2001, and the related statements of consolidated income, cash flows and changes in shareholders' equity for each of the three years in the period ended December 31, 2002. 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 auditing standards generally accepted in the United States of America. 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 Southern California Gas Company and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002, in conformity with accounting principles generally accepted in the United States of America. /S/ DELOITTE & TOUCHE LLP San Diego, California February 14, 2003 59 SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME Dollars in millions
Years ended December 31, 2002 2001 2000 ------ ------ ------ OPERATING REVENUES $2,858 $3,716 $2,854 ------ ------ ------ OPERATING EXPENSES Cost of natural gas distributed 1,192 2,117 1,361 Other operating expenses 872 792 695 Depreciation 276 268 263 Income taxes 183 165 173 Franchise fees and other taxes 93 101 96 ------ ------ ------ Total operating expenses 2,616 3,443 2,588 ------ ------ ------ Operating Income 242 273 266 ------ ------ ------ Other Income and (Deductions) Interest income 5 22 27 Regulatory interest (4) (19) (12) Allowance for equity funds used during construction 10 6 3 Taxes on non-operating income 5 (4) (10) Other - net (1) (2) 7 ------ ------ ------ Total 15 3 15 ------ ------ ------ Interest Charges Long-term debt 40 63 68 Other 7 7 8 Allowance for borrowed funds used during construction (3) (2) (2) ------ ------ ------ Total 44 68 74 ------ ------ ------ Net Income 213 208 207 Preferred Dividend Requirements 1 1 1 ------ ------ ------ Earnings Applicable to Common Shares $ 212 $ 207 $ 206 ====== ====== ====== See notes to Consolidated Financial Statements.
60 SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS Dollars in millions
December 31, --------------------- 2002 2001 -------- -------- ASSETS Utility plant - at original cost $6,701 $6,466 Accumulated depreciation (3,914) (3,710) ------ ------ Utility plant - net 2,787 2,756 ------ ------ Current assets: Cash and cash equivalents 22 13 Accounts receivable - trade 458 413 Accounts receivable - other 44 21 Due from unconsolidated affiliates 81 2 Income taxes receivable 28 -- Deferred income taxes 87 62 Regulatory assets arising from fixed-priced contracts and other derivatives 92 85 Fixed-price contracts and other derivatives -- 59 Inventories 76 42 Other 20 4 ------ ------ Total current assets 908 701 ------ ------ Other assets: Regulatory assets arising from fixed-priced contracts and other derivatives 233 150 Sundry 151 126 ------ ------ Total other assets 384 276 ------ ------ Total assets $4,079 $3,733 ====== ====== See notes to Consolidated Financial Statements.
61 SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS Dollars in millions
December 31, -------------------- 2002 2001 -------- -------- CAPITALIZATION AND LIABILITIES Capitalization: Common stock (100,000,000 shares authorized; 91,300,000 shares outstanding) $ 836 $ 835 Retained earnings 482 470 ------ ------ Total common equity 1,318 1,305 Preferred stock 22 22 ------ ------ Total shareholders' equity 1,340 1,327 Long-term debt 657 579 ------ ------ Total capitalization 1,997 1,906 ------ ------ Current liabilities: Short-term debt -- 50 Accounts payable - trade 199 160 Accounts payable - other 36 80 Due to unconsolidated affiliates 31 27 Regulatory balancing accounts - net 184 158 Income taxes payable -- 32 Interest payable 24 23 Regulatory liabilities 16 18 Fixed-price contracts and other derivatives 96 85 Current portion of long-term debt 175 100 Customer deposits 108 42 Other 264 279 ------ ------ Total current liabilities 1,133 1,054 ------ ------ Deferred credits and other liabilities: Customer advances for construction 37 29 Deferred income taxes 237 183 Deferred investment tax credits 47 50 Regulatory liabilities 201 174 Fixed-price contracts and other derivatives 233 154 Deferred credits and other liabilities 194 183 ------ ------ Total deferred credits and other liabilities 949 773 ------ ------ Contingencies and commitments (Note 10) Total liabilities and shareholders' equity $4,079 $3,733 ====== ====== See notes to Consolidated Financial Statements.
62 SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS Dollars in millions
Years Ended December 31, 2002 2001 2000 ------- ------- ------- CASH FLOWS FROM OPERATING ACTIVITIES Net Income $ 213 $ 208 $ 207 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation 276 268 263 Deferred income taxes and investment tax credits 32 9 (4) Changes in other assets 12 (12) 13 Changes in other liabilities 8 12 12 Changes in working capital components: Accounts receivable (67) 244 (378) Fixed-price contracts and other derivatives 60 16 -- Inventories (34) 25 11 Other current assets (4) 4 (75) Accounts payable (5) (171) 203 Income taxes (61) (58) 86 Due to/from affiliates - net 12 5 (3) Regulatory balancing accounts 26 (356) 332 Regulatory assets and liabilities 1 39 (2) Customer deposits 66 8 1 Other current liabilities (8) 39 68 ------- ------- ------- Net cash provided by operating activities 527 280 734 ------- ------- ------- CASH FLOWS FROM INVESTING ACTIVITIES Capital expenditures (331) (294) (198) Loan to affiliate - net (86) 233 (132) Other - net -- -- 21 ------- ------- ------- Net cash used in investing activities (417) (61) (309) ------- ------- ------- CASH FLOWS FROM FINANCING ACTIVITIES Dividends paid (201) (191) (201) Issuance of long-term debt 250 -- -- Payments on long-term debt (100) (270) (30) Increase (decrease) in short-term debt (50) 50 -- ------- ------- ------- Net cash used in financing activities (101) (411) (231) ------- ------- ------- Increase (decrease) in cash and cash equivalents 9 (192) 194 Cash and cash equivalents, January 1 13 205 11 ------- ------- ------- Cash and cash equivalents, December 31 $ 22 $ 13 $ 205 ======= ======= ======= SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION Interest payments, net of amounts capitalized $ 36 $ 65 $ 77 ======= ======= ======= Income tax payments, net of refunds $ 206 $ 216 $ 101 ======= ======= ======= See notes to Consolidated Financial Statements.
63 SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY Years ended December 31, 2002, 2001 and 2000 Dollars in millions
Accumulated Other Total Comprehensive Preferred Common Retained Comprehensive Shareholders' Income Stock Stock Earnings Income(Loss) Equity - ------------------------------------------------------------------------------------------------------------- Balance at December 31, 1999 $ 22 $ 835 $ 447 $ 6 $1,310 Net income $ 207 207 207 Other comprehensive income adjustment: Available-for-sale securities (10) (10) (10) Pension 3 3 3 ----- Comprehensive income $ 200 ===== Preferred stock dividends declared (1) (1) Common stock dividends declared (200) (200) - ------------------------------------------------------------------------------------------------------------- Balance at December 31, 2000 22 835 453 (1) 1,309 Net income $ 208 208 208 Other comprehensive income adjustment 1 1 1 ----- Comprehensive income $ 209 ===== Preferred stock dividends declared (1) (1) Common stock dividends declared (190) (190) - ------------------------------------------------------------------------------------------------------------- Balance at December 31, 2001 22 835 470 -- 1,327 Net income/comprehensive income $ 213 213 213 Preferred stock dividends declared ===== (1) (1) Common stock dividends declared (200) (200) Capital contribution 1 1 - ------------------------------------------------------------------------------------------------------------- Balance at December 31, 2002 $ 22 $ 836 $ 482 $ -- $1,340 ============================================================================================================= See notes to Consolidated Financial Statements.
64 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS SOUTHERN CALIFORNIA GAS COMPANY The following notes to Consolidated Financial Statements of Pacific Enterprises are incorporated herein by reference insofar as they relate to Southern California Gas Company: Note 1 - Significant Accounting Policies Note 2 - Short-term Borrowings Note 3 - Long-term Debt Note 6 - Stock-based Compensation Note 7 - Financial Instruments Note 9 - Regulatory Matters Note 10 - Commitments and Contingencies The following additional notes apply only to Southern California Gas Company: NOTE 4. INCOME TAXES The reconciliation of the statutory federal income tax rate to the effective income tax rate is as follows: Years ended December 31 2002 2001 2000 - --------------------------------------------------------------------- Statutory federal income tax rate 35.0% 35.0% 35.0% Depreciation 5.1 5.3 5.6 State income taxes - net of federal income tax benefit 7.0 6.7 6.8 Tax credits (0.8) (0.8) (0.7) Other - net (0.8) (1.4) 0.2 ------------------------ Effective income tax rate 45.5% 44.8% 46.9% - --------------------------------------------------------------------- The components of income tax expense are as follows: (Dollars in millions) 2002 2001 2000 - --------------------------------------------------------------------- Current: Federal $ 107 $ 126 $ 144 State 39 34 42 ------------------------ Total 146 160 186 ------------------------ Deferred: Federal 33 8 - State 2 4 (1) ------------------------ Total 35 12 (1) ------------------------ Deferred investment tax credits - net (3) (3) (2) ------------------------ Total income tax expense $ 178 $ 169 $ 183 - --------------------------------------------------------------------- 65 Federal and state income taxes are allocated between operating income and other income. SoCalGas is included in the consolidated income tax return of Sempra Energy and is allocated income tax expense from Sempra Energy in an amount equal to that which would result from having always filed a separate return. Accumulated deferred income taxes at December 31 consist of the following: (Dollars in millions) 2002 2001 - --------------------------------------------------------------------- Deferred Tax Liabilities: Differences in financial and tax bases of utility plant $ 258 $ 263 Regulatory balancing accounts 54 56 Other 20 20 ------------------- Total deferred tax liabilities 332 339 ------------------- Deferred Tax Assets: Investment tax credits 32 35 Other deferred liabilities 157 174 Other (7) 9 ------------------- Total deferred tax assets 182 218 ------------------- Net deferred income tax liability $ 150 $ 121 - --------------------------------------------------------------------- The net deferred income tax liability is recorded on the Consolidated Balance Sheets at December 31 as follows: (Dollars in millions) 2002 2001 - --------------------------------------------------------------------- Current asset $ (87) $ (62) Noncurrent liability 237 183 ------------------- Total $ 150 $ 121 - --------------------------------------------------------------------- 66 NOTE 5. EMPLOYEE BENEFIT PLANS The following tables provide a reconciliation of the changes in the plans' projected benefit obligations and the fair value of assets over the two years, and a statement of funded status as of each year end:
Other Pension Benefits Postretirement Benefits -------------------------------------------- (Dollars in millions) 2002 2001 2002 2001 - ----------------------------------------------------------------------------------------- WEIGHTED-AVERAGE ASSUMPTIONS AS OF DECEMBER 31: Discount rate 6.50% 7.25% 6.50% 7.25% Expected return on plan assets 8.00% 8.00% 8.00% 8.00% Rate of compensation increase 4.50% 5.00% 4.50% 5.00% Cost trend of covered health-care charges -- -- 7.00%(1) 7.25%(1) CHANGE IN PROJECTED BENEFIT OBLIGATION: Net obligation at January 1 $1,111 $1,125 $ 457 $ 415 Service cost 27 25 10 9 Interest cost 86 78 35 32 Plan amendments 48 -- -- -- Actuarial (gain) loss 98 (46) 177 23 Transfer of liability (2) 91 -- 30 -- Benefits paid (93) (71) (27) (22) -------------------------------------------- Net obligation at December 31 1,368 1,111 682 457 -------------------------------------------- CHANGE IN PLAN ASSETS: Fair value of plan assets at January 1 1,452 1,682 392 434 Actual return on plan assets (168) (162) (44) (33) Employer contributions 1 -- 17 13 Transfer of assets (2) 97 3 30 -- Other -- -- 2 -- Benefits paid (93) (71) (27) (22) -------------------------------------------- Fair value of plan assets at December 31 1,289 1,452 370 392 -------------------------------------------- Plan assets net of benefit obligation at December 31 (79) 341 (312) (65) Unrecognized net actuarial gain 82 (322) 235 (23) Unrecognized prior service cost 78 35 -- -- Unrecognized net transition obligation 1 2 80 88 -------------------------------------------- Net recorded asset at December 31 $ 82 $ 56 $ 3 $ -- - ----------------------------------------------------------------------------------------- (1) Decreasing to ultimate trend of 6.50% in 2004. (2) To reflect transfer of plan assets and liability from Sempra Energy. 67 The following table provides the amounts recognized on the Consolidated Balance Sheets (under noncurrent sundry assets) at December 31: Other Pension Benefits Postretirement Benefits ------------------------------------------- (Dollars in millions) 2002 2001 2002 2001 - ----------------------------------------------------------------------------------------- Prepaid benefit cost $ 93 $ 67 $ 3 $ -- Accrued benefit cost (11) (11) -- -- Additional minimum liability -- (2) -- -- Intangible asset -- 1 -- -- Accumulated other comprehensive income, pretax -- 1 -- -- ------------------------------------------- Net recorded asset $ 82 $ 56 $ 3 $ -- - -----------------------------------------------------------------------------------------
The following table provides the components of net periodic benefit cost for the plans:
Other (Dollars in millions) Pension Benefits Postretirement Benefits -------------------------------------------------- Years ended December 31 2002 2001 2000 2002 2001 2000 - ----------------------------------------------------------------------------------------- Service cost $ 27 $ 25 $ 23 $ 10 $ 9 $ 8 Interest cost 86 78 84 35 32 28 Expected return on assets (130) (129) (131) (35) (34) (32) Amortization of: Transition obligation 1 1 1 8 8 9 Prior service cost 4 3 4 -- -- -- Actuarial gain (19) (28) (29) -- (3) (8) Special termination benefits -- -- 33 -- -- 7 Regulatory adjustment 32 51 18 24 29 28 -------------------------------------------------- Total net periodic benefit cost $ 1 $ 1 $ 3 $ 42 $ 41 $ 40 - -----------------------------------------------------------------------------------------
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 $ 8 $ (6) Effect on the health-care component of the accumulated other postretirement benefit obligation $111 $(89) - ------------------------------------------------------------------------ Other postretirement benefits include retiree life insurance, medical benefits for retirees and their spouses, and Medicare Part B reimbursement for certain retirees. 68 Savings Plans The company offers savings plans, administered by plan trustees, to all eligible employees. Eligibility to participate in the plans is immediate for salary deferrals. Employees may contribute, subject to plan provisions, from one percent to 25 percent of their regular earnings. After one year of completed service, the company begins to make matching contributions. Employer contributions are equal to 50 percent of the first 6 percent of eligible base salary contributed by employees and, if certain company goals are met, an additional amount related to incentive compensation payments. Employer contributions are invested in Sempra Energy common stock and must remain so invested until termination of employment. At the direction of the employees, the employees' contributions are invested in Sempra Energy stock, mutual funds, or institutional trusts. Employer contributions for the SoCalGas plans are partially funded by the Sempra Energy Employee Stock Ownership Plan and Trust. Company contributions to the savings plans were $8 million in 2002, $7 million in 2001 and $5 million in 2000. NOTE 8. PREFERRED STOCK - ------------------------------------------------------------------ December 31, (Dollars in millions) 2002 2001 - ------------------------------------------------------------------ $25 par value, authorized 1,000,000 shares 6% Series, 79,011 shares outstanding $ 3 $ 3 6% Series A, 783,032 shares outstanding 19 19 Without par value, authorized 10,000,000 shares -- -- --------------- Total preferred stock $ 22 $ 22 - ----------------------------------------------------------------- None of SoCalGas' preferred stock is callable. All series have one vote per share and cumulative preferences as to dividends, and have a liquidation value of $25 per share, plus any unpaid dividends. In addition, the 6% Series preferred stock would also share pro rata with common stock in the remaining assets. 69 NOTE 11. QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarters ended ------------------------------------------------ (Dollars in millions) March 31 June 30 September 30 December 31 - -------------------------------------------------------------------------------------- 2002 Operating revenues $ 722 $ 680 $ 597 $ 859 Operating expenses 655 622 533 806 ----------------------------------------------- Operating income $ 67 $ 58 $ 64 $ 53 ------------------------------------------------ Net income $ 60 $ 52 $ 56 $ 45 Dividends on preferred stock -- 1 -- -- ------------------------------------------------ Earnings applicable to common shares $ 60 $ 51 $ 56 $ 45 ================================================ 2001 Operating revenues $ 1,548 $ 927 $ 561 $ 681 Operating expenses 1,480 862 488 614 ------------------------------------------------ Operating income $ 68 $ 65 $ 73 $ 67 ------------------------------------------------ Net income $ 51 $ 48 $ 57 $ 52 Dividends on preferred stock -- 1 -- -- ------------------------------------------------ Earnings applicable to common shares $ 51 $ 47 $ 57 $ 52 ================================================
The sum of the quarterly amounts does not necessarily equal the annual totals due to rounding. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURES None. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required on Identification of Directors is incorporated by reference from "Election of Directors" in the Information Statement prepared for the May 2003 annual meeting of shareholders. The information required on the companies' executive officers is set forth below. 70 Name Age* Position - ------------------------------------------------------------------- Pacific Enterprises -- Stephen L. Baum 61 Chairman, Chief Executive Officer and President John R. Light 61 Executive Vice President and General Counsel Neal E. Schmale 56 Executive Vice President and Chief Financial Officer Frank H. Ault 58 Senior Vice President and Controller Charles A. McMonagle 52 Vice President and Treasurer Thomas C. Sanger 59 Corporate Secretary Southern California Gas Company -- Edwin A. Guiles 53 Chairman and Chief Executive Officer Debra L. Reed 46 President and Chief Financial Officer Steven D. Davis 46 Senior Vice President, Customer Service and External Relations Margot A. Kyd 49 Senior Vice President, Corporate Business Solutions Roy M. Rawlings 58 Senior Vice President, Distribution Operations William L. Reed 50 Senior Vice President, Regulatory Affairs Lee M. Stewart 57 Senior Vice President, Gas Transmission Terry M. Fleskes 46 Vice President and Controller * As of December 31, 2002. Each Executive Officer has been an officer or employee of Sempra Energy or one of its subsidiaries for more than five years, with the exception of Mr. Light. Prior to joining the company in 1998, Mr. Light was a partner in the law firm of Latham & Watkins. Each executive officer of Southern California Gas Company holds the same position at San Diego Gas & Electric Company. 71 ITEM 11. EXECUTIVE COMPENSATION The information required by Item 11 is incorporated by reference from "Election of Directors" and "Executive Compensation" in the Information Statement prepared for the May 2003 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 "Share Ownership" in the Information Statement prepared for the May 2003 annual meeting of shareholders. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS. None. ITEM 14. CONTROLS AND PROCEDURES. The company has designed and maintains disclosure controls and procedures to ensure that information required to be disclosed in the company's reports under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission and is accumulated and communicated to the company's management, including its Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. In designing and evaluating these controls and procedures, management recognizes that any system of controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired objectives and necessarily applies judgment in evaluating the cost- benefit relationship of other possible controls and procedures. In addition, the company has investments in unconsolidated entities that it does not control or manage and, consequently, its disclosure controls and procedures with respect to these entities are necessarily substantially more limited than those it maintains with respect to its consolidated subsidiaries. Under the supervision and with the participation of management, including the Chief Executive Officer and the Chief Financial Officer, the company within 90 days prior to the date of this report has evaluated the effectiveness of the design and operation of the company's disclosure controls and procedures. Based on that evaluation, the company's Chief Executive Officer and Chief Financial Officer have concluded that the controls and procedures are effective. There have been no significant changes in the company's internal controls or in other factors that could significantly affect the internal controls subsequent to the date the company completed its evaluation. 72 PART IV ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K (a) The following documents are filed as part of this report: 1. Financial statements Page in This Report Independent Auditors' Report for Pacific Enterprises . . . . . . . . 27 Pacific Enterprises Statements of Consolidated Income for the years ended December 31, 2002, 2001 and 2000 . . . . . . . 28 Pacific Enterprises Consolidated Balance Sheets at December 31, 2002 and 2001 . . . . . . . . . . . . . . . . . . 29 Pacific Enterprises Statements of Consolidated Cash Flows for the years ended December 31, 2002, 2001 and 2000 . . . . . . . 31 Pacific Enterprises Statements of Consolidated Changes in Shareholders' Equity for the years ended December 31, 2002, 2001 and 2000 . . . . . . . . . . . . . . . . . 32 Pacific Enterprises Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . 33 Independent Auditors' Report for Southern California Gas Company. . .59 Southern California Gas Company Statements of Consolidated Income for the years ended December 31, 2002, 2001 and 2000 . . . . . . . 60 Southern California Gas Company Consolidated Balance Sheets at December 31, 2002 and 2001. . . . . . . . . . . . . . . . . . . 61 Southern California Gas Company Statements of Consolidated Cash Flows for the years ended December 31, 2002, 2001 and 2000. . 63 Southern California Gas Company Statements of Consolidated Changes in Shareholders' Equity for the years ended December 31, 2002, 2001 and 2000 . . . . . . . . . . . . . . . . . . . . . . . 64 Southern California Gas Company Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . 65 2. Financial statement schedules The following document may be found in this report at the indicated page number. Schedule I--Condensed Financial Information of Parent. . . . . . . . 76 Any other schedules for which provision is made in Regulation S-X are not required under the instructions contained therein, are inapplicable or the information is included in the Consolidated Financial Statements and notes thereto. 73 3. Exhibits See Exhibit Index on page 80 of this report. (b) Reports on Form 8-K The following reports on Form 8-K were filed after September 30, 2002: None. 74 INDEPENDENT AUDITORS' CONSENTS AND REPORT ON SCHEDULE To the Board of Directors and Shareholders of Pacific Enterprises: We consent to the incorporation by reference in Registration Statement Numbers 2-96782, 33-26357, 2-66833, 2-96781, 33-21908, and 33-54055 on Form S-8 and Registration Statement Numbers 33-24830, 333-52926, and 33- 44338 on Form S-3 of Pacific Enterprises of our report dated February 14, 2003, appearing in this Annual Report on Form 10-K of Pacific Enterprises for the year ended December 31, 2002. Our audits of the financial statements referred to in our aforementioned report also included the financial statement schedule of Pacific Enterprises, listed in Item 15. 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 February 25, 2003 To the Boards of Directors and Shareholders of Southern California Gas Company: We consent to the incorporation by reference in Registration Statement Numbers 333-70654, 333-45537, 33-51322, 33-53258, 33-59404, and 33-52663 on Form S-3 of our report dated February 14, 2003, appearing in this Annual Report on Form 10-K of Southern California Gas Company for the year ended December 31, 2002. /S/ DELOITTE & TOUCHE LLP San Diego, California February 25, 2003 76 Schedule I -- CONDENSED FINANCIAL INFORMATION OF PARENT PACIFIC ENTERPRISES Condensed Statements of Income (Dollars in millions)
For the years ended December 31 2002 2001 2000 -------- -------- -------- Other income $ 16 $ 23 $ 33 Expenses, interest and income taxes 19 28 32 -------- -------- -------- Income (loss) before subsidiary earnings (3) (5) 1 Subsidiary earnings 212 207 206 -------- -------- -------- Earnings applicable to common shares $ 209 $ 202 $ 207 ======== ======== ======== Condensed Balance Sheets (Dollars in millions) Balance at December 31 2002 2001 -------- -------- Assets: Current assets $ 71 $ 55 Investment in subsidiary 1,318 1,305 Due from affiliates - long-term 419 409 Deferred charges and other assets 87 102 -------- -------- Total Assets $ 1,895 $ 1,871 ======== ======== Liabilities and Shareholders' Equity: Due to affiliates $ 65 $ 147 Other current liabilities 36 30 -------- -------- Total current liabilities 101 177 Other long-term liabilities 110 120 Common equity 1,604 1,494 Preferred stock 80 80 -------- -------- Total Liabilities and Shareholders' Equity $ 1,895 $ 1,871 ======== ========
76 Schedule I (Continued)-- CONDENSED FINANCIAL INFORMATION OF PARENT PACIFIC ENTERPRISES Condensed Statements of Cash Flows (Dollars in millions)
For the years ended December 31 2002 2001 2000 -------- -------- -------- Net cash provided by (used in) operating activities $ (5) $ 8 $ (96) -------- -------- -------- Dividends received from subsidiaries 200 190 200 -------- -------- -------- Cash flows provided by investing activities 200 190 200 -------- -------- -------- Common dividends paid (100) (190) (100) Preferred dividends paid (4) (4) (4) Due to/from affiliates - net (91) -- -- Other -- (4) -- -------- -------- -------- Cash flows used in financing activities (195) (198) (104) -------- -------- -------- Change in Cash and Cash Equivalents -- -- -- Cash and Cash Equivalents, January 1 -- -- -- -------- -------- -------- Cash and Cash Equivalents, December 31 $ -- $ -- $ -- ======== ======== ========
77 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. PACIFIC ENTERPRISES By: /s/ Stephen L. Baum Stephen L. Baum Chairman, Chief Executive Officer and President 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 Officer: Stephen L. Baum Chairman, Chief Executive Officer and President /s/ Stephen L. Baum February 18, 2003 Principal Financial Officer: Neal E. Schmale Executive Vice President and Chief Financial Officer /s/ Neal E. Schmale February 18, 2003 Principal Accounting Officer: Frank H. Ault Senior Vice President and Controller /s/ Frank H. Ault February 18, 2003 Directors: Stephen L. Baum, Chairman /s/ Stephen L. Baum February 18, 2003 John R. Light, Director /s/ John R. Light February 18, 2003 Neal E. Schmale, Director /s/ Neal E. Schmale February 18, 2003
78 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. SOUTHERN CALIFORNIA GAS COMPANY By: /s/ Edwin A. Guiles . Edwin A. Guiles 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 Officer: Edwin A. Guiles Chairman and Chief Executive Officer /s/ Edwin A. Guiles February 17, 2003 Principal Financial Officer: Debra L. Reed President and Chief Financial Officer /s/ Debra L. Reed February 17, 2003 Principal Accounting Officer: Terry M. Fleskes Vice President and Controller /s/ Terry M. Fleskes February 17, 2003 Directors: Edwin A. Guiles Chairman /s/ Edwin A. Guiles February 17, 2003 Debra L. Reed, Director /s/ Debra L. Reed February 17, 2003 Frank H. Ault, Director /s/ Frank H. Ault February 17, 2003
79 EXHIBIT INDEX The Forms 8-K, 10-K and 10-Q referred to herein were filed under Commission File Number 1-14201 (Sempra Energy), Commission File Number 1-40 (Pacific Enterprises) and/or Commission File Number 1-1402 (Southern California Gas Company). Exhibit 3 -- By-Laws and Articles Of Incorporation 3.01 Articles of Incorporation of Pacific Enterprises (Pacific Enterprises 1996 Form 10-K, Exhibit 3.01). 3.02 Restated Bylaws of Pacific Enterprises dated November 6, 2001. 3.03 Restated Articles of Incorporation of Southern California Gas Company (Southern California Gas Company 1996 Form 10-K, Exhibit 3.01). 3.04 Restated Bylaws of Southern California Gas Company dated November 6, 2001. Exhibit 4 -- Instruments Defining The Rights Of Security Holders The Company agrees to furnish a copy of each such instrument to the Commission upon request. 4.01 Specimen Common Stock Certificate of Pacific Enterprises (Pacific Enterprises 1988 Form 10-K, Exhibit 4.01). 4.02 Specimen Preferred Stock Certificates of Pacific Enterprises (Pacific Lighting Corporation 1980 Form 10-K, Exhibit 4.02). 4.03 Specimen Preferred Stock Certificates of Southern California Gas Company (Southern California Gas Company 1980 Form 10-K, Exhibit 4.01). 4.04 First Mortgage Indenture of Southern California Gas Company to American Trust Company dated October 1, 1940 (Registration Statement No. 2-4504 filed by Southern California Gas Company on September 16, 1940, Exhibit B-4). 4.05 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). 4.06 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). 4.07 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). 80 4.08 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). 4.09 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). 4.10 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). 4.11 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). 4.12 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). 4.13 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). 4.14 Supplemental Indenture of Southern California Gas Company to U.S. Bank, N.A., successor to First Trust of California, N.A. dated as of October 1, 2002 (2002 Sempra Energy Form 10-K, Exhibit 4.17). 4.15 Specimen 7 3/4% Series Preferred Stock Certificate (Southern California Gas Company 1992 Form 10-K, Exhibit 4.15). Exhibit 10 -- Material Contracts Compensation 10.01 Sempra Energy Executive Incentive Plan effective January 1, 2003 (2002 Sempra Energy Form 10-K, Exhibit 10.09). 10.02 Amended Sempra Energy Retirement Plan for Directors (2002 Sempra Energy Form 10-K, Exhibit 10.10). 10.03 Amended and Restated Sempra Energy Deferred Compensation and Excess Savings Plan (Sempra Energy September 30, 2002 Form 10-Q, Exhibit 10.3). 10.04 Sempra Energy Executive Security Bonus Plan effective January 1, 2001 (2001 Sempra Energy Form 10-K, Exhibit 10.08). 10.05 Form of Sempra Energy Severance Pay Agreement for Executives (2001 Sempra Energy Form 10-K, Exhibit 10.07). 81 10.06 Sempra Energy Deferred Compensation and Excess Savings Plan effective January 1, 2000 (Sempra Energy 2000 Form 10-K, Exhibit 10.07). 10.07 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). 10.08 Pacific Enterprises Employee Stock Ownership Plan and Trust Agreement as amended effective October 1, 1992. (Pacific Enterprises 1992 Form 10-K, Exhibit 10.18). 10.09 Amended and Restated Pacific Enterprises Employee Stock Option Plan (Southern California Gas Company 1996 Form 10-K, Exhibit 10.10). Exhibit 12 -- Statement Re: Computation of Ratios 12.01 Pacific Enterprises Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2002, 2001, 2000, 1999 and 1998. 12.02 Southern California Gas Company Computation of Ratio of Earnings to Fixed Charges for the years ended December 31, 2002, 2001, 2000, 1999 and 1998, Exhibit 21 -- Subsidiaries 21.01 Pacific Enterprises Schedule of Subsidiaries at December 31, 2002. 21.02 Southern California Gas Company Schedule of Subsidiaries at December 31, 2002. Exhibit 23 -- Independent Auditor's Consents, page 75. 82 GLOSSARY AFUDC Allowance for Funds Used During Construction BCAP Biennial Cost Allocation Proceeding Bcf Billion Cubic Feet (of natural gas) CA/AZ California/Arizona COS Cost of Service CPUC California Public Utilities Commission DSM Demand Side Management EITF Emerging Issues Task Force Enova Enova Corporation EPA Environmental Protection Agency ERMG Energy Risk Management Group ESOP Employee Stock Ownership Plan FASB Financial Accounting Standards Board FERC Federal Energy Regulatory Commission GCIM Gas Cost Incentive Mechanism Global Sempra Energy Global Enterprises IOUs Investor-Owned Utilities LIFO Last in first out inventory costing method mmbtu Million British Thermal Units (of natural gas) ORA Office of Ratepayer Advocates Parent Sempra Energy PBR Performance-Based Ratemaking/Regulation PE Pacific Enterprises PGA Purchased Gas Balancing Account PRP Potentially Responsible Party RD&D Research, Development and Demonstration ROE Return on Equity ROR Rate of Return S&P Standard & Poor's 83 SDG&E San Diego Gas & Electric Company SEC Securities and Exchange Commission SFAS Statement of Financial Accounting Standards SoCalGas Southern California Gas Company TURN The Utility Reform Network UEG Utility Electric Generation VaR Value at Risk 84 CERTIFICATIONS I, Stephen L. Baum, certify that: 1. I have reviewed this Annual Report on Form 10-K of Pacific Enterprises; 2. Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Annual Report; 3. Based on my knowledge, the financial statements and other financial information included in this Annual Report fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Annual Report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Annual Report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this Annual Report (the "Evaluation Date"); and c) presented in this Annual Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 1. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 1. The registrant's other certifying officers and I have indicated in this Annual Report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. February 26, 2003 /s/ Stephen L. Baum Stephen L. Baum Chief Executive Officer 85 I, Neal E. Schmale, certify that: 1. I have reviewed this Annual Report on Form 10-K of Pacific Enterprises; 2. Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Annual Report; 3. Based on my knowledge, the financial statements and other financial information included in this Annual Report fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Annual Report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Annual Report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this Annual Report (the "Evaluation Date"); and c) presented in this Annual Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 1. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 1. The registrant's other certifying officers and I have indicated in this Annual Report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. February 26, 2003 /s/ Neal E. Schmale Neal E. Schmale Chief Financial Officer 86 I, Edwin A. Guiles, certify that: 1. I have reviewed this Annual Report on Form 10-K of Southern California Gas Company; 2. Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Annual Report; 3. Based on my knowledge, the financial statements and other financial information included in this Annual Report fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Annual Report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Annual Report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this Annual Report (the "Evaluation Date"); and c) presented in this Annual Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 1. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 1. The registrant's other certifying officers and I have indicated in this Annual Report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. February 26, 2003 /s/ Edwin A. Guiles Edwin A. Guiles Chief Executive Officer 87 I, Debra L. Reed, certify that: 1. I have reviewed this Annual Report on Form 10-K of Southern California Gas Company; 2. Based on my knowledge, this Annual Report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this Annual Report; 3. Based on my knowledge, the financial statements and other financial information included in this Annual Report fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this Annual Report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this Annual Report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this Annual Report (the "Evaluation Date"); and c) presented in this Annual Report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 1. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 1. The registrant's other certifying officers and I have indicated in this Annual Report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. February 26, 2003 /s/ Debra L. Reed Debra L. Reed Chief Financial Officer 88 EX-12 3 pe_ratios2002.txt EXHIBIT 12.01 EXHIBIT 12.1 PACIFIC ENTERPRISES COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (Dollars in millions)
1998 1999 2000 2001 2002 -------- -------- -------- -------- -------- Fixed Charges: Interest $ 84 $ 82 $ 72 $ 88 $ 63 Interest portion of annual rentals 11 3 4 3 2 Preferred dividends of subsidiaries (1) 2 2 2 2 2 -------- -------- -------- -------- -------- Total Fixed Charges for Purpose of Ratio $ 97 $ 87 $ 78 $ 93 $ 67 ======== ======== ======== ======== ======== Earnings: Pretax income from continuing operations $274 $350 $396 $377 $383 Total Fixed Charges (from above) 97 87 78 93 67 -------- -------- -------- ------- --------- Total Earnings for Purpose of Ratio $371 $437 $474 $470 $450 ======== ======== ======== ======= ========= Ratio of Earnings to Fixed Charges 3.82 5.02 6.08 5.05 6.72 ======== ======== ======== ======= ========= (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-12 4 scg_ratios2002.txt EXHIBIT 12.02 EXHIBIT 12.2 SOUTHERN CALIFORNIA GAS COMPANY COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES (Dollars in millions)
1998 1999 2000 2001 2002 -------- -------- -------- -------- -------- Fixed Charges: Interest $ 81 $ 62 $ 72 $ 70 $ 47 Interest portion of annual rentals 4 3 4 3 2 -------- -------- -------- -------- -------- Total fixed charges for purpose of ratio $ 85 $ 65 $ 76 $ 73 $ 49 ======== ======== ======== ======== ======== Earnings: Pretax income from continuing operations $287 $383 $390 $377 $391 Add: Total fixed charges (from above) 85 65 76 73 49 -------- -------- -------- ------- --------- Total earnings for purpose of ratio $372 $448 $466 $450 $440 ======== ======== ======== ======= ========= Ratio of earnings to fixed charges 4.38 6.89 6.13 6.16 8.98 ======== ======== ======== ======= =========
EX-21 5 pe_ex21.txt EXHIBIT 21.01 EXHIBIT 21.01 PACIFIC ENTERPRISES Schedule of Subsidiaries at December 31, 2002 Subsidiary State of Incorporation - ---------- ---------------------- Ecotrans OEM Corporation California Southern California Gas Company California Southern California Gas Tower California EX-21 6 scg_ex21.txt EXHIBIT 21.02 EXHIBIT 21.02 SOUTHERN CALIFORNIA GAS COMPANY Schedule of Subsidiaries at December 31, 2002 Subsidiary State of Incorporation - ---------- ---------------------- Ecotrans OEM Corporation California Southern California Gas Tower California -----END PRIVACY-ENHANCED MESSAGE-----