-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, JCfHmMCXzO2VaNlGyrgcxoJLEO16sdvoJeM2YeIHSx0eOKwhr9tbj4DmK0scCGa/ QiX0VkCTiXedS+cRTD5DrQ== 0000912057-95-001491.txt : 19950615 0000912057-95-001491.hdr.sgml : 19950615 ACCESSION NUMBER: 0000912057-95-001491 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19941231 FILED AS OF DATE: 19950320 SROS: NYSE SROS: PSE 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-K405 SEC ACT: 1934 Act SEC FILE NUMBER: 001-01402 FILM NUMBER: 95521770 BUSINESS ADDRESS: STREET 1: 555 W FIFTH ST STREET 2: ML 14H1 CITY: LOS ANGELES STATE: CA ZIP: 90013 BUSINESS PHONE: 2132441200 MAIL ADDRESS: STREET 1: PO BOX 3249 CITY: LOS ANGELES STATE: CA ZIP: 90051-1249 10-K405 1 FORM 10-K405 FORM 10-K SECURITIES AND EXCHANGE COMMISSION Washington, D. C. 20549 [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [Fee Required] For the fiscal year ended December 31, 1994 Commission file number 1-1402 SOUTHERN CALIFORNIA GAS COMPANY ----------------------------------------- (Exact name of Registrant as specified in its charter) California 95-1240705 - ------------------------ --------------------------------- (State of incorporation) (IRS Employer Identification No.) 555 West Fifth Street, Los Angeles, California 90013-1011 - ---------------------------------------------- -------------- (Address of principal executive offices) (Zip Code) (213) 244-1200 ---------------------------------------------------- (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Name of each exchange --------------------- Title of each class on which registered ------------------- ------------------- Preferred Stock Pacific Stock Exchange - --------------- 6% Cumulative Preferred - Series A 7-3/4% Series Preferred Stock First Mortgage Bonds New York Stock Exchange - -------------------- Series X, due 2020 (9-3/4%) Series Y, due 2021 (8-3/4%) Series Z, due 2002 (6-7/8%) Series AA, due 1997 (6-1/2%) Series BB, due 2023 (7-3/8%) Series CC, due 1998 (5-1/4%) Series DD, due 2023 (7-1/2%) Series EE, due 2025 (6-7/8%) Series FF, due 2003 (5-3/4%) Securities registered pursuant to Section 12(g) of the Act: None - 1 - 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] The aggregate market value of Registrant's voting stock (Preferred Stock) held by non-affiliates at March 14, 1995, was approximately $87 million. This amount excludes the market value of 49,369 shares of Preferred Stock held by Registrant's parent, Pacific Enterprises. All of the Registrant's Common Stock is owned by Pacific Enterprises. DOCUMENTS INCORPORATED BY REFERENCE Certain information in this Annual Report is incorporated by reference to information contained or to be contained in other documents filed or to be filed by Registrant with the Securities and Exchange Commission. The following table identifies the information so incorporated in each Part of this Annual Report on Form 10-K and the document in which it is or will be contained. Information Incorporated by Reference and Document Annual Report in Which Information is or On Form 10-K will be Contained ------------ ----------------------- Part III - Information contained under the captions "Election of Directors", "Share Ownership of Directors and "Executive Officers" and "Executive Compensation" in Registrant's Information Statement for its Annual Meeting of Shareholders scheduled to be held on May 2, 1995. - 2 - TABLE OF CONTENTS PART I Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . . . 5 Operating Statistics. . . . . . . . . . . . . . . . 5 Service Area. . . . . . . . . . . . . . . . . . . . 7 Utility Services. . . . . . . . . . . . . . . . . . 8 Demand for Gas. . . . . . . . . . . . . . . . . . . 8 Competition . . . . . . . . . . . . . . . . . . . . 9 Supplies of Gas . . . . . . . . . . . . . . . . . . 9 Rates and Regulation. . . . . . . . . . . . . . . . 12 Environmental Matters . . . . . . . . . . . . . . . 13 Employees . . . . . . . . . . . . . . . . . . . . . . . . . . 13 Management. . . . . . . . . . . . . . . . . . . . . . . . . . 14 Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . 15 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . 15 Item 4. Submission of Matters to a Vote of Security Holders . . . . . 15 PART II Item 5. Market for Registrant's Common Equity and Related Stockholder Matters. . . . . . . . . . . . 16 Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . 16 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations. . . . . . . . . . . . . . . . . . . . . . . . . . 17 Item 8. Financial Statements and Supplementary Data. . . . . . . . . . . . . . . . . . . . . . 25 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure. . . . . . . . . . . . . . . . . . . . . 45 PART III Item 10. Directors and Executive Officers of the Registrant . . . . . . . . . . . . . . . . . . . . . . 46 - 3 - Item 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . 46 Item 12. Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . 46 Item 13. Certain Relationships and Related Transactions. . . . . . . . . . . . . . . . . . . . . . . . . 46 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K . . . . . . . . . . . . . . . . . . . 47 - 4 - PART I ITEM 1. BUSINESS Southern California Gas Company (The Gas Company or the Company) is a public utility owning and operating a natural gas distribution, transmission and storage system that supplies natural gas in 535 cities and communities throughout a 23,000-square mile service territory comprising most of southern California and parts of central California. The Gas Company is the principal subsidiary of Pacific Enterprises (the "Parent"). The Gas Company is the nation's largest natural gas distribution utility. It serves approximately 17 million residential, commercial, industrial, utility electric generation and wholesale customers through approximately 4.7 million meters in its service territory. Most of those meters represent "core" customers, which are primarily residential and small commercial and industrial accounts. The Gas Company's "noncore" customers are served by over 1,200 meters. Noncore customers consist of large-volume gas users such as electric utilities, wholesale and large commercial and industrial customers. The Company is subject to regulation by the California Public Utilities Commission (CPUC) which, among other things, establishes rates the Company may charge for gas service, including an authorized rate of return on investment. Under current ratemaking policies, the Company's future earnings and cash flow will be determined primarily by the allowed rate of return on common equity, the growth in rate base, noncore market pricing and the variance in gas volumes delivered to noncore customers versus CPUC-adopted forecast deliveries and the ability of management to control expenses and investment in line with the amounts authorized by the CPUC to be collected in rates. The impact of any future regulatory restructuring, such as performance based ratemaking ("PBR") (See "Rates and Regulation"), and increased competitiveness in the industry, including the continuing threat of customers bypassing the Company's system and obtaining service directly from interstate pipelines, and electric industry restructuring, may also affect the Company's performance. For 1995, the CPUC has authorized the Company to earn a rate of return on rate base of 9.67 percent and a 12.00 percent rate of return on common equity compared to 9.22 percent and 11.00 percent, respectively, in 1994. Growth in rate base for 1994 was approximately 3 percent. Rate base is expected to remain at the same level in 1995. The Company has achieved or exceeded its authorized rate of return on rate base for the last twelve consecutive years. The Gas Company was incorporated in California in 1910. Its principal executive offices are located at 555 West Fifth Street, Los Angeles, California 90013 and its telephone number is (213) 244-1200. OPERATING STATISTICS The following table sets forth certain operating statistics of the Company from 1990 through 1994. - 5 - OPERATING STATISTICS
Year Ended December 31 ---------------------------------------------------------------------- 1994 1993 1992 1991 1990 ---- ---- ---- ---- ---- Gas Sales, Transportation & Exchange Revenues (thousands of dollars): Residential $1,712,899 $1,652,562 $1,483,654 $1,673,837 $1,547,492 Commercial/Industrial 798,180 853,579 836,672 977,065 1,057,030 Utility Electric Generation 118,353 147,208 194,639 148,573 235,102 Wholesale 98,354 116,737 128,881 144,779 164,716 Exchange 690 3,745 5,863 7,482 8,496 ---------- ---------- ---------- ---------- ---------- Total in rates 2,728,476(1) 2,773,831 2,649,709 2,951,736 3,012,836 Regulatory balancing accounts and other (141,952) 37,243 190,216 (21,430) 199,789 ---------- ---------- ---------- ---------- ---------- Operating Revenue $2,586,524 $2,811,074 $2,839,925 $2,930,306 $3,212,625 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Volumes (millions of cubic feet): Residential 256,400 247,507 243,920 249,522 261,887 Commercial/Industrial 347,419 339,706 363,124 460,368 436,330 Utility Electric Generation 260,290 212,720 220,642 170,043 158,985 Wholesale 146,279 147,978 149,232 141,931 139,034 Exchange 10,002 16,969 23,888 25,604 30,246 --------- ------- --------- --------- --------- Total 1,020,390 964,880 1,000,806 1,047,468 1,026,482 --------- ------- --------- --------- --------- --------- ------- --------- --------- --------- Core 341,469 338,795 334,630 351,432 372,677 Noncore 678,921 626,085 666,176 696,036 653,805 --------- ------- --------- --------- --------- Total 1,020,390 964,880 1,000,806 1,047,468 1,026,482 --------- ------- --------- --------- --------- --------- ------- --------- --------- --------- Sales 362,624 352,052 355,177 411,414 515,757 Transportation 647,764 595,859 621,741 610,450 480,479 Exchange 10,002 16,969 23,888 25,604 30,246 --------- ------- --------- --------- --------- Total 1,020,390 964,880 1,000,806 1,047,468 1,026,482 --------- ------- --------- --------- --------- --------- ------- --------- --------- --------- Revenues (per thousand cubic feet): Residential $6.68 $6.68 $6.08 $6.71 $5.91 Commercial/Industrial $2.30 $2.51 $2.30 $2.12 $2.42 Utility Electric Generation $0.45 $0.69 $0.88 $0.87 $1.48 Wholesale $0.67 $0.79 $0.86 $1.02 $1.18 Exchange $0.07 $0.22 $0.25 $0.29 $0.28 Customers Active Meters (at end of period): Residential 4,483,324 4,459,250 4,445,500 4,429,896 4,381,563 Commercial 187,518 187,602 189,364 193,051 193,409 Industrial 23,505 23,924 24,419 25,642 26,530 Utility Electric Generation 8 8 8 8 8 Wholesale 3 3 2 2 2 --------- --------- --------- --------- --------- Total 4,694,358 4,670,787 4,659,293 4,648,599 4,601,512 --------- --------- --------- --------- --------- --------- --------- --------- --------- --------- Residential Meter Usage (annual average): Revenues $383 $371 $334 $380 $356 Volumes (thousands of cubic feet) 57.4 55.6 55.0 56.6 60.3 System Usage (millions of cubic feet): Average Daily Sendout 2,795 2,611 2,717 2,881 2,824 Peak Day Sendout 4,350 4,578 4,547 4,356 5,267 Sendout Capability (at end of period) 7,570 7,351 7,419 7,073 7,073 Degree Days(2): Number 1,438(3) 1,203 1,258 1,409 1,432 Average (20 Year) 1,418 1,430 1,458 1,474 1,506 Percent of Average 101.4% 84.1% 86.3% 95.6% 95.1% Population of Service Area (estimated at year end) 17,070,000 15,600,000 15,600,000 15,600,000 15,100,000 (1) Beginning January 1, 1994, rates included the ratepayer's portion of the Comprehensive Settlement (the amount included in rates for 1994 was $119 million). (2) The number of degree days for any period of time indicates whether the temperature is relatively hot or cold. A degree day is recorded for each degree the average temperature for any day falls below 65 degrees Fahrenheit. (3) Estimated calendar degree days.
- 6 - SERVICE AREA The Gas Company distributes natural gas throughout a 23,000-square mile service territory with a population of approximately 17 million people. As indicated by the following map, its service territory includes most of southern California and parts of central California. [MAP OF THE GAS COMPANY'S SERVICE TERRITORY] Natural gas service is also provided on a wholesale basis to the distribution systems of the City of Long Beach, San Diego Gas & Electric Company and Southwest Gas Company. - 7 - UTILITY SERVICES The Gas Company's customers are separated, for regulatory purposes, into core and noncore customers. Core customers are primarily residential and small commercial and industrial customers, without alternative fuel capability. Noncore customers primarily include utility electric generation, wholesale and large commercial and industrial customers. Noncore customers are sensitive to the price relationship between natural gas and alternate fuels, and are capable of readily switching from one fuel to another, subject to air quality regulations. The Gas Company offers two basic utility services, sale of gas and transmission of gas. Residential customers and most other core customers purchase gas directly from The Gas Company. Noncore customers and large core customers have the option of purchasing gas either from The Gas Company or from other sources (such as brokers or producers) for delivery through the Company's transmission and distribution system. Smaller customers are permitted to aggregate their gas requirements and also to purchase gas directly from brokers or producers, up to a limit of 10 percent of the Company's core market. The Gas Company generally earns the same margin whether the Company buys the gas and sells it to the customer or transports gas already owned by the customer. (See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Operating Results.") The Gas Company continues to be obligated to purchase reliable supplies of natural gas to serve the requirements of its core customers. However, the only gas supplies that the Company may offer for sale to noncore customers are the same supplies that it purchases to serve its core customers. The Gas Company also provides a gas storage service for noncore customers on a bid basis. The storage service program provides opportunities for customers to store gas on an "as available" basis during the summer to reduce winter purchases when gas costs are generally higher, or to reduce their level of winter curtailment in the event temperatures are unusually cold. During 1994, The Gas Company stored approximately 24 billion cubic feet of customer-owned gas. DEMAND FOR GAS Natural gas is a principal energy source in the Company's service area for residential, commercial and industrial uses as well as utility electric generation (UEG) requirements. Gas competes with electricity for residential and commercial cooking, water heating and space heating uses, and with other fuels for large industrial, commercial and UEG uses. Demand for natural gas in southern California is expected to continue to increase but at a slower rate due primarily to a slowdown in housing starts, new energy efficient building construction and appliance standards and general recessionary business conditions. During 1994, 97 percent of residential energy customers in the Company's service territory used natural gas for water heating and 94 percent for space heating. Approximately 78 percent of those customers used natural gas for cooking and 72 percent for clothes drying. Demand for natural gas by noncore customers such as large volume commercial, industrial and electric generating customers is very sensitive to the price of alternative competitive fuels. These customers number only approximately 1,200; however, during 1994, they accounted for approximately 17 percent of total gas revenues, 67 percent of total gas volumes delivered and 14 percent of the authorized gas margin. Changes in the cost of gas or alternative fuels, primarily fuel oil, can result in significant shifts in this market, subject to air quality regulations. Demand - 8 - for gas for UEG use is also affected by the price and availability of electric power generated in other areas and purchased by the Company's UEG customers. COMPETITION Since interstate pipelines began operations in The Gas Company's service territories, the Company's throughput to customers in the Kern County area who use natural gas to produce steam for enhanced oil recovery projects has decreased significantly because of the bypass of the Company's system. The decrease in revenues from enhanced oil recovery customers is subject to full balancing account treatment, except for a five percent incentive to the Company for attaining certain throughput levels, and therefore, does not have a material impact on earnings. However, bypass of other Company markets also may occur. The Company is fully at risk for lost noncore volumes due to competition, and would not receive balancing account treatment except in the enhanced oil recovery market. In order to respond to certain bypass threats, the Company has received authorization from the CPUC for expedited review of price discounts proposed for long-term gas transportation contracts with some noncore customers. The CPUC has also approved changes in the methodology for allocating the Company's costs between core and noncore customers to reduce the subsidization of core customer rates by noncore customers. These decisions have resulted in a reduction of noncore rates and a corresponding increase in core rates that better reflects the cost of serving each customer class and, together with price discounting authority, has enabled the Company to better compete with new interstate pipelines for noncore customers. In addition, in August 1993 a capacity brokering program was implemented. Under the program, for a fee, the Company provides to noncore customers, or others, a portion of its control of interstate pipeline capacity to allow more direct access to producers. Also, the Comprehensive Settlement (See "Item 7. Management's Discussion and Analysis of Financial Condition and Result of Operations - Ratemaking Procedures - Comprehensive Settlement of Regulatory Issues.") will help improve the Company's competitiveness by reducing the cost of transportation service to noncore customers. Historically, environmental laws have favorably impacted the use of natural gas in the Company's service territory, particularly by utility electric generation customers. However, increasingly complex administrative requirements may discourage natural gas use by large commercial and industrial customers. In April 1994, the CPUC announced it would review the structure of California's electric utility service, a review that could lead to significant changes in the way investor-owned utilities conduct business, including the amount of electricity purchased from out-of-state suppliers. The CPUC's proposed deregulation of electricity sales by the year 2002 may affect the future volumes of natural gas the Company transports for electric utilities. Utility electric generation customers currently account for 26 percent of the Company's annual throughput. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation - Factors Influencing Future Performance - Electric Industry Restructuring." SUPPLIES OF GAS In 1994, The Gas Company delivered approximately 1 trillion cubic feet of natural gas through its system. Approximately 65 percent of these deliveries were customer-owned gas for which The Gas Company provided transportation services, compared to 64 percent in 1993. The balance of gas deliveries was gas purchased by The Gas Company and resold to customers. Most of the natural gas delivered by The Gas Company is produced outside of California. These supplies are delivered to the California border by interstate pipeline companies - 9 - (primarily El Paso Natural Gas Company and Transwestern Natural Gas Company) that provide transportation services for supplies purchased from other sources by The Gas Company or its transportation customers. These supplies enter The Gas Company's intrastate transmission system at the California border for delivery to customers. The Gas Company currently has paramount rights to daily deliveries of up to 2,200 million cubic feet of natural gas over the interstate pipeline systems of El Paso Natural Gas Company (up to 1,450 million cubic feet) and Transwestern Pipeline Company (up to 750 million cubic feet). The rates that interstate pipeline companies may charge for gas and transportation services and other terms of service are regulated by the Federal Energy Regulatory Commission (FERC). Existing interstate pipeline capacity into California exceeds current demand by over 1 billion cubic feet per day. Up to 2 billion cubic feet per day of capacity on the El Paso and Transwestern interstate pipeline systems, representing over $175 million and $55 million, respectively, of reservation charges annually, may be relinquished within the next few years based on existing contract reduction options and contract expirations. Some of this capacity may not be resubscribed. Current FERC regulation could permit costs of unsubscribed capacity to be allocated to remaining firm service customers, including The Gas Company. Under existing regulation in California, the Company would have the opportunity to include its portion of any such reallocated costs in its rates. If competitive conditions did not support higher rates resulting from these reallocated costs, then the Company would be at risk for lost revenues in the noncore market. The Company, as a part of a coalition of customers who hold 90 percent of the firm transportation capacity rights on the El Paso and Transwestern systems, has offered a proposal for market based rates with balanced incentives to El Paso and Transwestern to resolve the issue of unsubscribed capacity. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Factors Influencing Future Performance - Excess Interstate Pipeline Capacity." - 10 - The following table sets forth the sources of gas deliveries by The Gas Company from 1990 through 1994. SOURCES OF GAS --------------
Year Ended December 31 ---------------------------------------------------------------------- 1994 1993 1992 1991 1990 ---- ---- ---- ---- ---- Gas Purchases: (Millions of Cubic Feet) Market Gas: 30-Day 98,071 84,696 20,695 139,649 148,849 Other 148,371 159,197 198,049 168,486 225,710 --------- ------- --------- --------- --------- Total Market Gas 246,442 243,893 218,744 308,135 374,559 Affiliates 101,276 96,559 99,226 98,566 103,406 California Producers & Federal Offshore 36,158 28,107 42,262 39,613 52,633 --------- ------- --------- --------- --------- Total Gas Purchases 383,876 368,559 360,232 446,314 530,598 Customer-Owned Gas and Exchange Receipts 658,293 622,307 641,080 629,038 531,263 Storage Withdrawal (Injection) - Net (9,299) (9,498) 14,379 (8,451) (13,288) Company Use and Unaccounted For (12,480) (16,488) (14,885) (19,432) (22,091) --------- ------- --------- --------- --------- Net Gas Deliveries 1,020,390 964,880 1,000,806 1,047,469 1,026,482 --------- ------- --------- --------- --------- --------- ------- --------- --------- --------- Gas Purchases: (Thousands of dollars) Commodity Costs $ 643,865 $ 815,145 $ 805,550 $1,071,445 $1,371,854 Fixed Charges* 368,516 397,714 397,579 358,294 405,233 ---------- ---------- ---------- ---------- ---------- Total Gas Purchases $1,012,381 $1,212,859 $1,203,129 $1,429,739 $1,777,087 ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- Average Cost of Gas Purchased (Dollars per Thousand Cubic Feet)** $1.68 $2.21 $2.24 $2.40 $2.59 ----- ----- ----- ----- ----- ----- ----- ----- ----- ----- * 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 the Company. ** The average commodity cost of gas purchased excludes fixed charges.
- 11 - Market sensitive gas supplies (supplies purchased on the spot market as well as under longer-term contracts ranging from one month to ten years based on spot prices) accounted for approximately 64 percent of total gas volumes purchased by the Company during 1994, as compared with 66 percent and 61 percent, respectively, during 1993 and 1992. These supplies were generally purchased at prices significantly below those for other long-term sources of supply. On March 16, 1994, the CPUC approved a new process for evaluating the Company's gas purchases substantially replacing the previous process of reasonableness reviews. The new "Gas Cost Incentive Mechanism" ("GCIM") is a three-year pilot program that began in April 1994. The GCIM essentially compares the Company's cost of gas with a benchmark level. See "Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Ratemaking Procedures - GCIM." The Gas Company estimates that sufficient natural gas supplies will be available to meet the requirements of its customers into the next century. RATES AND REGULATION The Gas Company is regulated by the CPUC. The CPUC consists of five commissioners appointed by the Governor of California for staggered six-year terms. It is the responsibility of the CPUC to determine that utilities operate in the best interest of the ratepayer with an opportunity to earn a reasonable profit. The regulatory structure is complex and has a very substantial impact on the profitability of the Company. Under current ratemaking procedures, the return that the Company is authorized to earn is the product of an authorized rate of return on rate base and the amount of rate base. Rate base consists primarily of net investment in utility plant. Thus, the Company's earnings are affected by changes in the authorized rate of return on rate base and the growth in rate base and by the Company's ability to control expenses and investment in rate base within the amounts authorized by the CPUC in setting rates. In addition, the Company's ability to achieve its authorized rate of return is affected by other regulatory and operating factors. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Ratemaking Procedures." The Gas Company's operating and fixed costs, including return on rate base, are allocated between core and noncore customers under a methodology that is based upon the costs incurred in serving these customer classes. For 1995, approximately 89 percent of the CPUC-authorized gas margin has been allocated to core customers and 11 percent to noncore customers, including wholesale customers. Under the current regulatory framework, costs may be reallocated between the core and the noncore customer classes once every other year in a biennial cost allocation proceeding (BCAP). During 1994, the Company began exploring a new approach for setting rates to its customers known as "Performance Based Ratemaking." This new approach, PBR, would maintain cost based rates but would link financial performance with increases and decreases in productivity and generally would allow for rates to increase by the rate of inflation, less an agreed upon adjustment for productivity improvements. The Gas Company proposes to file a PBR application with the CPUC in 1995, and if approved, the change would not take effect until January 1, 1997, at the earliest. Although PBR could result in increased earnings volatility, the Company would have the opportunity to improve financial performance to the extent it was able to reduce expenses, increase energy deliveries and generate profits from new products and - 12 - services. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Factors Influencing Future Performance." ENVIRONMENTAL MATTERS The Gas Company has identified and reported to California environmental authorities 42 former gas manufacturing sites for which it (together with other utilities as to 21 of the sites) may have remedial obligations under environmental laws. As of December 31, 1994, eight of the sites have been remediated, of which five have received certification from the California Environmental Protection Agency. Preliminary investigations, at a minimum, have been completed on thirty-three of the sites, including those sites at which the remediations described above have been completed. In addition, the Company is one of a large number of major corporations that have been identified as a potentially responsible party for environmental remediation of three industrial waste disposal sites and a landfill site. These 46 sites are in various stages of investigation or remediation. It is anticipated that the investigation, and if necessary, remediation of these sites will be completed over a period of from ten years to twenty years. In May 1994, the CPUC approved a collaborative settlement between the Company and other California utilities and the Division of Ratepayer Advocates which provides for rate recovery of 90 percent of environmental investigation and remediation costs without reasonableness review. In addition, the utilities have the opportunity to retain a percentage of any insurance recovery to offset the 10 percent of costs not recovered in rates. At December 31, 1994, the Company's estimated remaining liability for investigation and remediation for the 46 sites was approximately $65 million, which it is authorized to recover through the rate recovery mechanism described above. The estimated liability is subject to future adjustment pending further investigation. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation - Factors Influencing Future Performance - Environmental Matters." Because of the current and expected rate recovery, the Company believes that compliance with environmental laws and regulations will not have a material adverse effect on its financial statements. EMPLOYEES The Company employs approximately 8,200 persons. Most field, clerical and technical employees of the Company are represented by the Utility Workers' Union of America or the International Chemical Workers' Union. Collective bargaining agreements covering these approximately 5,560 employees expire with respect to wages and working conditions on March 31, 1996 and with respect to medical benefits on December 31, 1995. The agreement with respect to all benefits except medical expires on March 31, 1995, and the Company is currently in the process of negotiating a new agreement. In order to enhance its overall competitiveness, the Company has also continued to downsize. In 1994, approximately 800 positions were eliminated and the Company expects to eliminate another 300-500 positions in 1995 as a result of efficiency and productivity improvements, and more reductions will result from organizational realignment. In addition, the Company has a competitive benchmarking program that compares the costs of retaining certain support functions versus outsourcing them. Functions which cannot be performed at competitive rates may be contracted to outside providers. - 13 - MANAGEMENT The executive officers of Southern California Gas Company are as follows:
Became an Executive Name Age Position Officer - ---- --- -------- ------- Warren I. Mitchell 57 President August 1981 Lloyd A. Levitin 62 Executive Vice President and June 1993 Chief Financial Officer Debra L. Reed 38 Senior Vice President August 1988 Lee M. Stewart 49 Senior Vice President November 1990 Paul J. Cardenas 48 Vice President January 1995 Pamela J. Fair 36 Vice President January 1995 Eric B. Nelson 45 Vice President January 1995 Richard M. Morrow 45 Vice President January 1995 Roy M. Rawlings 50 Vice President January 1987 Anne S. Smith 41 Vice President November 1991 George E. Strang 55 Vice President July 1984 Ralph Todaro 44 Vice President and Controller November 1988 Dennis V. Arriola 34 Treasurer August 1994
All of the Company's executive officers have been employed by the Company, the Parent, or its affiliates in management positions for more than the past five years, except for Mr. Arriola. From 1987 until joining the Company in August 1994, Mr. Arriola was a Vice President of Bank of America NT&SA (1992-1994) and a Vice President of Security Pacific National Bank (1987-1992). Executive officers are elected annually and serve at the pleasure of the Board of Directors. There are no family relationships among any of the Company's executive officers. - 14 - ITEM 2. PROPERTIES At December 31, 1994, The Gas Company owned approximately 3,040 miles of transmission and storage pipeline, 42,683 miles of distribution pipeline and 42,647 miles of service piping. It also owned 13 transmission compressor stations and 6 underground storage reservoirs (with a combined working storage capacity of approximately 116 billion cubic feet) and general office buildings, shops, service facilities, and certain other equipment necessary in the conduct of its business. Southern California Gas Tower, a wholly-owned subsidiary of The Gas Company, has a 15 percent limited partnership interest in a 52-story office building in downtown Los Angeles. The Gas Company occupies about half of the building. ITEM 3. LEGAL PROCEEDINGS Except for the matters referred to in the financial statements filed with or incorporated by reference in Item 8 or referred to elsewhere in this Annual Report, neither the Company nor any of its subsidiaries is a party to, nor is their property the subject of, any material pending legal proceedings other than routine litigation incidental to their businesses. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS No matters were submitted during the fourth quarter of 1994 to a vote of the Company's security holders. - 15 - PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS The Parent owns all of the Company's Common Stock. The information required by this item concerning dividends declared is included in the Statement of Consolidated Shareholders' Equity set forth in Item 8 of this Annual Report. Such information is incorporated herein by reference. RANGE OF MARKET PRICES OF PREFERRED STOCK
Three Months Ended 1994 1993 - -------------------------------------------------------------------------------------------- Preferred Stock: 7 3/4% 6%-Series A 7 3/4% 6%-Series A ------ ----------- ------ ----------- March 31 $26 1/4 - 24 5/8 $21 1/2 - 20 $27 - 24 5/8 $21 5/8 - 19 1/2 June 30 $25 1/4 - 23 1/4 $20 3/4 - 18 3/4 $27 - 25 1/8 $22 3/4 - 20 Sept. 30 $24 1/4 - 22 3/8 $19 1/2 - 17 3/4 $27 - 26 $23 1/4 - 22 1/4 Dec. 31 $23 3/8 - 21 $18 - 16 1/4 $26 7/8 - 25 1/2 $22 3/4 - 20 1/4
Market prices for the preferred stock were obtained from the Pacific Stock Exchange. (The 7 3/4% preferred stock began trading in April 1993 therefore, estimates for the first quarter were obtained from the underwriter). The 6% Preferred Stock and the Flexible Auction Series Preferred Stock, Series A and Series C are not listed on any exchange. ITEM 6. SELECTED FINANCIAL DATA The following table sets forth certain selected financial data of the Company for 1990 through 1994. SELECTED FINANCIAL DATA
--------------------------------------------------------------------------- Year Ended December 31 - --------------------------------------------------------------------------------------------- (Thousands of 1994 1993 1992 1991 1990 Dollars) ---- ---- ---- ---- ---- - -------- Operating revenues $2,586,524 $2,811,074 $2,839,925 $2,930,306 $3,212,625 Net income $ 190,513 $ 193,676 $ 194,716 $ 211,792* $ 177,744 Total assets $4,775,763 $4,950,220 $4,155,399 $4,059,186 $4,013,497 Long-term debt $1,396,931 $1,235,622 $1,147,198 $1,147,132 $1,016,493 *Net income for 1991 includes a net after-tax gain of $15 million relating to the sale of The Gas Company's headquarters office property.
The Gas Company's parent, Pacific Enterprises, owns 96 percent of the voting stock, including all of the issued and outstanding common stock; therefore, per share data have been omitted. - 16 - ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Southern California Gas Company (the "Company") is a subsidiary of Pacific Enterprises (the "Parent"). The Company, a public utility, provides natural gas distribution, transmission and storage in a 23,000-square mile service area in southern California and parts of central California. This section includes management's analysis of operating results from 1992 through 1994, and is intended to provide additional information about the Company's financial performance. This section also focuses on major factors expected to influence future operating results and discusses future investment and financing plans. This section should be read in conjunction with the Consolidated Financial Statements set forth in Item 8. OPERATIONS The Company's markets are separated into core customers and noncore customers. Core customers consist of approximately 4.7 million customers (4.5 million residential and 0.2 million smaller commercial and industrial customers). The noncore market consists of approximately 1,200 customers which primarily include utility electric generation, wholesale, and large commercial and industrial customers. Many noncore customers are sensitive to the price relationship between natural gas and alternate fuels, and are capable of readily switching from one fuel to another, subject to air quality regulations. FINANCIAL RESULTS Under current utility ratemaking policies, the return that the Company is authorized to earn is the product of an authorized rate of return on rate base and the amount of rate base. Rate base consists primarily of net investment in utility plant. Thus, the Company's earnings are affected by changes in the authorized rate of return on rate base and the growth in rate base and by the Company's ability to control expenses and investment in rate base within the amounts authorized by the California Public Utilities Commission ("CPUC") in setting rates. In addition, achievement of the authorized rate of return is affected by other regulatory and operating factors. The Company is exploring a new approach for setting rates to its customers as discussed in Factors Influencing Future Performance. Key financial and operating data for the Company are highlighted in the table below.
(Dollars in Millions) 1994 1993 1992 - ---------------------------------------------------------------------------------------- Net income (after preferred dividends) $180 $184 $188 Authorized return on rate base 9.22% 9.99% 10.49% Authorized return on common equity 11.00% 11.90% 12.65% Weighted average rate base $2,862 $2,769 $2,720 Growth in weighted average rate base over prior period 3.4% 1.8% 2.1% - ----------------------------------------------------------------------------------------
Net income decreased $4 million in 1994 due primarily to a reduction in the Company's authorized rate of return on common equity from 11.90 percent in 1993 to 11.00 percent in 1994 partially offset by reductions in operating expenses, higher earnings from the noncore market and the growth in rate base. During 1993, net income decreased $4 million due primarily to a reduction in the Company's authorized rate of return on common equity and lower earnings from the noncore market, partially offset by reductions in the Company's cost of service, including operating and financing costs, and growth in rate base. - 17 - The Company has achieved or exceeded the rate of return on rate base authorized by the CPUC for 12 consecutive years. In 1994, the Company achieved a 9.74 percent return on rate base compared to a 9.22 percent authorized return and a 12.33 percent return on equity compared to an 11.00 percent authorized return. The improved returns were primarily due to more efficient operations through aggressive reductions in operating expenses, noncore earnings and a conservation award. The Company plans to continue efforts to reduce costs in 1995. In 1995, the Company is authorized to earn 9.67 percent on rate base and 12.00 percent on common equity. Rate base is expected to remain at the same level as 1994. The Company's operating revenues decreased $224 million in 1994. The decrease reflects a reduction in authorized gas margin and the average unit cost of gas partially offset by the growth in rate base and an increase in noncore volumes transported. The Company's cost of gas distributed decreased $195 million in 1994. The decrease reflects a lower average unit cost of gas in 1994 partially offset by a slight increase in core volumes delivered. Core volumes increased as a result of colder weather in 1994 compared to 1993. The Company's operating revenues decreased $29 million from 1992 to 1993. The decrease reflects a reduction in authorized gas margin, the average unit cost of gas and noncore volumes transported partially offset by the growth in rate base. The Company's cost of gas distributed decreased $20 million in 1993. The decrease reflects a lower average unit cost of gas in 1993 partially offset by an increase in core volumes delivered. The average unit cost of gas has declined as a result of lower market prices. The average commodity cost of gas purchased by the Company, excluding fixed charges, for 1994 was $1.68 per thousand cubic feet, compared to $2.21 per thousand cubic feet in 1993 and $2.24 per thousand cubic feet in 1992. - 18 - OPERATING RESULTS The table below summarizes the components of throughput and revenue in rates charged to customers for the past three years. Beginning January 1, 1994, rates included the ratepayer portion of the Comprehensive Settlement (See Note 2 in Notes to Consolidated Financial Statements). The amount included in rates for 1994 was $119 million.
Transportation Gas Sales and Exchange Total --------- ------------ ----- (Dollars in millions, volume in billion cubic Throughput Revenue Throughput Revenue Throughput Revenue feet) - --------------------------------------------------------------------------------------------------------------------- 1994: Residential 254 $1,704 2 $ 9 256 $1,713 Commercial/Industrial 100 592 258 207 358 799 Utility Electric Generation 260 118 260 118 Wholesale 8 21 138 77 146 98 ------------------------------------------------------------------------------------------- Total in Rates 362 $2,317 658 $411 1,020 2,728 Balancing and Other (141) ---------- Total Operating Revenues $2,587 ------------------------------------------------------------------------------------------- 1993: Residential 244 $1,641 4 $ 12 248 $1,653 Commercial/Industrial 97 610 259 247 356 857 Utility Electric Generation 4 213 143 213 147 Wholesale 11 27 137 90 148 117 ------------------------------------------------------------------------------------------- Total in Rates 352 $2,282 613 $492 965 2,774 Balancing and Other 37 ---------- Total Operating Revenues $2,811 ------------------------------------------------------------------------------------------- 1992: Residential 241 $1,475 3 $ 9 244 $1,484 Commercial/Industrial 100 586 287 256 387 842 Utility Electric Generation 21 221 174 221 195 Wholesale 14 34 135 95 149 129 -------------------------------------------------------------------------------------------- Total in Rates 355 $2,116 646 $534 1,001 2,650 Balancing and Other 190 ----------- Total Operating Revenues $2,840 - --------------------------------------------------------------------------------------------------------------------- - ---------------------------------------------------------------------------------------------------------------------
Although the revenues from transportation throughput are less than for gas sales, the Company generally earns the same margin whether it buys the gas and sells it to the customer or transports gas already owned by the customer. For 1995, approximately 89 percent of total margin authorized is contributed by the core market (residential and smaller commercial and industrial customers), with 11 percent contributed by the noncore market. Throughput, the total gas sales and transportation volumes moved through the Company's system, has increased during 1994 as a result of greater weather-related demand in noncore volumes, primarily utility electric generation and large commercial and industrial customers. During 1993, throughput declined from 1992 levels as a result of bypass of the Company's system, primarily by enhanced oil recovery customers (See Factors Influencing Future Performance). - 19 - RATEMAKING PROCEDURES The Company is regulated by the CPUC. It is the responsibility of the CPUC to determine that utilities operate in the best interest of the ratepayer with the opportunity to earn a reasonable return on investment. Current ratemaking procedures are summarized below. GENERAL RATE CASES. General rate applications are filed every three years. In a general rate case, the CPUC establishes a margin, which is the amount of revenue authorized to be collected from customers to recover authorized operating expenses (other than the cost of gas as discussed below, see BCAP), depreciation, interest, taxes and return on rate base. Rate adjustments from the Company's next general rate case proceeding would normally be scheduled to go into effect in 1997, however, the Company has filed a petition for modification with the CPUC to delay the proceeding and is exploring a new approach for setting rates to its customers. Known as "Performance Based Ratemaking" (PBR), this new method would link financial performance with productivity improvements and generally would allow for rates to increase by the rate of inflation, less an agreed-upon percentage for productivity improvements. The Company proposes to file a PBR application with the CPUC in 1995 and if approved, to implement it in 1997 at the earliest. For a further discussion of PBR, see Factors Influencing Future Performance-Performance Based Ratemaking. ATTRITION. In a process referred to as the annual attrition allowance, the CPUC annually adjusts rates for years between general rate cases to cover the changes in rate base and the effects of inflation as adjusted by a productivity improvement factor. Separate proceedings are held annually to review the Company's cost of capital, including return on common equity, interest costs and changes in capital structure. The CPUC has authorized annual allowances for operational attrition for 1995 and 1996 to the extent that the annual inflation rate for those years exceeds 2 percent and 3 percent, respectively, for operating and maintenance expenses. This compares to a 3 percent productivity adjustment authorized for 1994. The rate base attrition will continue based upon a three year rolling average of recorded net utility plant additions. For further discussion of annual attrition allowances, see Note 2 of Notes to Consolidated Financial Statements. GCIM. On March 16, 1994, the CPUC approved a new process for evaluating the Company's gas purchases substantially replacing the previous process of reasonableness reviews. The new Gas Cost Incentive Mechanism (GCIM) is a three-year pilot program that began April 1, 1994. The GCIM essentially compares the Company's cost of gas with a benchmark level, which represents the average market price of 30-day firm spot supplies delivered to the Company's service area. All savings from gas purchased below the benchmark are shared equally between ratepayers and shareholders. The Company can recover all costs in excess of the benchmark, but within a tolerance band. If the Company's cost of gas exceeds the tolerance band, then the excess costs are shared equally between ratepayers and shareholders. For the first year of the program, the GCIM provides a 4.5 percent tolerance band above the benchmark. For the second and third years of the program, the tolerance band decreases to 4 percent. In 1994, since the inception of the GCIM, the Company's gas purchases were within the tolerance band. The Company enters into a certain amount of gas futures contracts in the open market to help reduce gas costs within the GCIM tolerance band. The Company's policy is to use gas futures contracts to mitigate risk and better manage gas costs. The CPUC has approved the use of gas futures for managing risk associated with the GCIM. For the year ended December 31, 1994, gains or losses from gas futures contracts are not material to the Company's financial statements. BCAP. In a biennial cost allocation proceeding (BCAP), the CPUC specifies for each two-year period the allocation of total authorized revenue requirements (including cost of gas) to be - 20 - collected from the Company's core and noncore customer classes. The Company maintains regulatory accounts to accumulate undercollections and overcollections from customers and makes periodic filings with the CPUC to adjust future rates to amortize outstanding balances in those accounts. In the most recent BCAP decision issued by the CPUC in December 1994, the Company has been authorized to collect a $130 million revenue increase effective January 1, 1995. Of this amount, $45 million has been authorized for the 1995 attrition allowance, $27 million as a result of the increase in the 1995 authorized rate of return on common equity and rate base, and $58 million for the BCAP. Included in the BCAP decision was a partial reallocation of costs to further reduce subsidies by nonresidential core customers to residential customers in order to better align residential rates with the cost of providing residential service. For the core market, the Company records margin ratably each month. The BCAP balancing account procedure, which substantially eliminates the effect on income of variances in gas costs and volumes sold, allows the Company to increase rates for increased gas acquisition costs or for revenue shortfalls due to reductions in demand by core customers, subject to the terms and conditions of the GCIM mechanism and the Comprehensive Settlement (as discussed below). Conversely, the Company reduces rates for decreased gas acquisition costs or higher than projected revenues from increases in demand by core customers. RESTRUCTURING OF GAS SUPPLY CONTRACTS. The Company and its gas supply affiliates restructured long-term gas supply contracts with suppliers of California offshore and Canadian gas. The Company's cost of these supplies had been substantially in excess of its average delivered cost of gas for all supplies. The new contracts substantially reduced the ongoing delivered costs of these gas supplies and provided for lump sum payments of $391 million to the suppliers. The expiration date for the Canadian gas supply contract was also shortened from 2012 to 2003. COMPREHENSIVE SETTLEMENT OF REGULATORY ISSUES. On July 20, 1994, the CPUC approved a comprehensive settlement (Comprehensive Settlement) of a number of pending regulatory issues including partial rate recovery of restructuring costs associated with the long-term gas supply contracts discussed above. The Comprehensive Settlement permits the Company to recover in utility rates approximately 80 percent of the contract restructuring costs of $391 million and accelerated amortization of related pipeline assets of approximately $140 million, together with interest, over a period of approximately five years (See Note 2 of Notes to Consolidated Financial Statements). FACTORS INFLUENCING FUTURE PERFORMANCE Under current ratemaking policies, future Company earnings and cash flow will be determined primarily by the allowed rate of return on common equity, the growth in rate base, noncore market pricing and the variance in gas volumes delivered to noncore customers versus CPUC-adopted forecast deliveries and the ability of management to control expenses and investment in line with the amounts authorized by the CPUC to be collected in rates. The impact of any future regulatory restructuring, such as Performance Based Ratemaking, increased competitiveness in the industry, including the continuing threat of customers bypassing the Company's system and obtaining service directly from interstate pipelines, and electric industry restructuring could also affect the Company's future performance. The Company's ability to report as earnings the results from revenues in excess of its authorized return from noncore customers due to volume increases has been substantially eliminated for the five years beginning August 1, 1994 as a consequence of the Comprehensive Settlement described above. This is because certain forecasted levels of gas deliveries in excess of the 1991 throughput levels used to - 21 - establish noncore rates were contemplated in estimating the costs of the Comprehensive Settlement at December 31, 1993. The following discussion addresses each of the major factors expected to influence future performance: ALLOWED RATE OF RETURN AND GROWTH IN RATE BASE. The Company's earnings for 1995 will be affected by the increase in the authorized rate of return on common equity, reflecting the overall increase in cost of capital. For 1995, the Company is authorized to earn a rate of return on rate base of 9.67 percent and a rate of return on common equity of 12.00 percent compared to 9.22 percent and 11.00 percent, respectively, in 1994. Rate base is expected to remain at the same level as 1994. NONCORE BYPASS. Since the completion of the Kern River and Mojave Interstate Pipelines in February 1992, the Company's throughput to customers in the Kern County area who use natural gas to produce steam for enhanced oil recovery projects, has decreased significantly because of the bypass of the Company's system. The Kern River and Mojave Interstate Pipelines now deliver natural gas to customers formerly served by the Company amounting to 350 million to 400 million cubic feet per day. The decrease in revenues from enhanced oil recovery customers is subject to full balancing account treatment, except for a 5 percent incentive to the Company, and therefore, does not have a material impact on the Company's earnings. However, bypass of other markets may also occur, and the Company is fully at risk for lost noncore volumes due to competition, and would not receive balancing account treatment except in the enhanced oil recovery market. NONCORE PRICING. In order to respond to certain bypass threats, the Company has received authorization from the CPUC for expedited review of price discounts proposed through long-term gas transportation contracts with some noncore customers. In addition, in December 1992, the CPUC approved changes in the methodology for allocating the Company's costs between core and noncore customers to reduce subsidization of core customer rates by noncore customers. Effective in June 1993, the CPUC implemented the new cost allocation policy known as "long-run marginal cost." The revised methodologies have resulted in a reduction of noncore rates and a corresponding increase in core rates that better reflects the cost of serving each customer class and, together with price discounting authority, has enabled the Company to better compete with new interstate pipelines for noncore customers. In addition, in August 1993 a capacity brokering program was implemented. Under the program, for a fee, the Company provides to noncore customers, or others, a portion of its control of interstate pipeline capacity to allow more direct access to producers. Also, the Comprehensive Settlement will help improve the Company's competitiveness by reducing the cost of transportation service to noncore customers. NONCORE THROUGHPUT. The Company's earnings are subject to variability if gas throughput to its noncore customers varies from estimates adopted by the CPUC in establishing rates. There is a continuing risk that an unfavorable variance in noncore volumes can result from external factors such as weather, the use of increased hydroelectric power, the price relationship between alternative fuels and natural gas, competing pipeline bypass of the Company's system and general economic conditions. In these cases the Company is at risk for the lost revenue. In addition, although an economic downturn or recession does not affect the Company as significantly as nonregulated businesses, there exists the risk that an unfavorable variance in the noncore volumes can result. MANAGEMENT CONTROL OF EXPENSES AND INVESTMENT. Over the past 12 years, management has been able to control operating expenses and investment within the amounts authorized to be collected in rates and intends to continue to do so to remain competitive and reduce the risk of bypass. Future cost reductions are expected, including employee reductions and productivity gains as a result of moving to a realigned business unit organization. In connection with the Comprehensive Settlement, the Company has agreed to absorb a 2 percent and 3 percent - 22 - productivity adjustment to its authorized level of operating and maintenance expenses in 1995 and 1996, respectively, before it can seek any rate recovery due to the effects of inflation. The Company also bears the risk of nonrecovery of margin or other costs authorized by the CPUC for the noncore market under the terms of the Comprehensive Settlement. Unanticipated significant increases in the inflation rate could also reduce earnings and cash flow. PERFORMANCE BASED RATEMAKING. During 1994, the Company began exploring a new approach for setting rates to its customers. Known as PBR, the new method would maintain cost based rates but would link financial performance with increases and decreases in productivity and generally would allow for rates to increase by the rate of inflation, less an agreed-upon adjustment for productivity improvements. Although PBR could result in increased earnings volatility, the Company would have the opportunity to improve financial performance to the extent it was able to reduce expenses, increase energy deliveries and generate profits from new products and services. Under PBR, the Company would be at risk for changes in interest rates and cost of capital, changes in core volumes not related to weather, and achieving the productivity improvements. The Company proposes to file a PBR application with the CPUC in 1995 and if approved, to implement it in 1997 at the earliest. ELECTRIC INDUSTRY RESTRUCTURING. Demand for natural gas by electric generation customers is sensitive to the price and availability of electric power generated in other areas and purchased by these electric generation customers. In April 1994, the CPUC announced it will review the structure of California's electric utility service, a review that could lead to significant changes in the way California's investor-owned electric utilities and cogenerators conduct business. The CPUC's proposal has no immediate effect on the Company's operations. However, the Company is closely monitoring the process and has taken an active role in the proceedings because of its considerable experience with natural gas deregulation and because future volumes of natural gas it transports for electric utilities could be adversely affected. In addition, as a result of restructuring, electric rates could become more competitive in the future. The following table indicates the comparative energy cost of gas versus the energy cost of electricity in 1995 for an average residential customer in the Company's service territory:
Fuel Price Price/MMBTU ---- ----- ----------- Natural Gas $.716/Therm $ 7.16 Electricity $.132/KWH $38.58
The electric industry restructuring may result in a reduction of electric rates to core customers, but it is unlikely to overcome the entire cost advantage of natural gas for residential heating. EXCESS INTERSTATE PIPELINE CAPACITY. Existing interstate pipeline capacity into California exceeds current demand by over 1 billion cubic feet per day. Up to 2 billion cubic feet per day of capacity on the El Paso and Transwestern interstate pipeline systems, representing over $175 million and $55 million, respectively, of reservation charges annually, may be relinquished within the next few years based on existing contract reduction options and contract expirations. Some of this capacity may not be resubscribed. Current FERC regulation could permit the cost of unsubscribed capacity to be allocated to remaining firm service customers, including the Company. Under existing regulation in California, the Company would have the opportunity to include its portion of any such reallocated costs in its rates. If competitive conditions did not support higher rates resulting from these reallocated costs, then the Company would be at risk for lost revenues in the noncore market. - 23 - The Company, as a part of a coalition of customers who hold 90 percent of the firm transportation capacity rights on the El Paso and Transwestern systems, has offered a proposal for market based rates with balanced incentives to El Paso and Transwestern to resolve the issue of stranded or unsubscribed capacity. Negotiations on a settlement of the issue, consistent with the coalition's proposal, are progressing with Transwestern. Discussions of the proposal with El Paso are continuing. ENVIRONMENTAL MATTERS. The Company's operations and those of its customers are affected by a growing number of environmental laws and regulations. These laws and regulations affect current operations as well as future expansion. Historically, environmental laws favorably impacted the use of natural gas in the Company's service territory, particularly by utility electric generation and large industrial customers. However, increasingly complex administrative requirements may discourage natural gas use by commercial and large industrial customers. Environmental laws also require clean up of facilities no longer in use. Because of current and expected rate recovery, the Company believes that compliance with these laws will not have a significant impact on its financial statements. For further discussion of regulatory and environmental matters, see Note 4 of Notes to Consolidated Financial Statements. CAPITAL EXPENDITURES Capital expenditures were $245 million, $318 million and $326 million in 1994, 1993 and 1992, respectively. Capital expenditures primarily represent ratebase investment. The decline in capital expenditures is due primarily to the continued sluggishness in the southern California economy, lower amounts required to replace aging pipeline and fewer large projects. Capital expenditures are estimated to be $250 million in 1995 and will be financed primarily by internally-generated funds. LIQUIDITY Cash and cash equivalents at December 31, 1994 was $58 million. Regulatory Accounts Receivable decreased in 1994 primarily due to overcollections under the BCAP balancing account procedures due primarily to lower gas prices than forecasted. Regulatory Accounts Receivable increased in 1993 and 1992 reflecting higher undercollections due primarily to core market throughput falling below CPUC-adopted forecast levels. Regulatory Assets decreased in 1994 primarily due to the recovery of $119 million related to the Comprehensive Settlement. In 1993, Accounts Payable-Other included the liability for lump sum settlement payments of $375 million to restructure long-term gas supply contracts which were paid in 1994. INTEREST EXPENSE. Interest expense on long-term debt was $89 million, $96 million and $107 million for 1994, 1993 and 1992, respectively. Interest expense in 1994 and 1993 was reduced from 1992 levels as a result of refinancing debt at lower interest rates. FUTURE BORROWINGS. At December 31, 1994, all financing for the Comprehensive Settlement has been completed. The Company has $330 million of commercial paper outstanding to finance the Comprehensive Settlement. This amount is expected to decline over the five year period of the Comprehensive Settlement as amounts are recovered in rates. The Company anticipates that cash requirements in 1995 for capital expenditures, dividends and debt requirements will come from cash generated from operating activities, existing cash balances and any future refinancing of existing debt. Future refinancings are expected to include a combination of commercial paper and medium-term notes. - 24 - ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA STATEMENT OF CONSOLIDATED INCOME
Year Ended December 31 -------------------------------------- (Thousands of Dollars) 1994 1993 1992 - ------------------------------------------------------------------------------- OPERATING REVENUES $2,586,524 $2,811,074 $2,839,925 ---------- ---------- ---------- OPERATING EXPENSES Cost of gas distributed 991,625 1,187,072 1,207,275 Operation 745,961 768,677 730,638 Maintenance 80,980 99,795 101,680 Depreciation 233,580 228,244 219,011 Income taxes 145,603 134,491 164,487 Local franchise payments 41,966 46,217 50,743 Ad valorem taxes 36,901 32,592 37,677 Payroll and other taxes 31,281 29,488 29,030 ---------- ---------- ---------- Total 2,307,897 2,526,576 2,540,541 ---------- ---------- ---------- Net Operating Revenue 278,627 284,498 299,384 ---------- ---------- ---------- OTHER INCOME AND (DEDUCTIONS) Interest income 6,623 1,668 3,948 Regulatory interest 14,046 4,924 1,731 Allowance for equity funds used during construction 2,394 4,406 3,608 Income taxes on non-operating income 941 5,670 572 Other - net (7,033) (5,245) (11,314) ---------- ---------- ---------- Total 16,971 11,423 (1,455) ---------- ---------- ---------- INTEREST CHARGES AND (CREDITS) Interest on long-term debt 89,023 95,806 106,641 Other interest 17,425 9,180 (1,132) Allowance for borrowed funds used during construction (1,363) (2,741) (2,296) ---------- ---------- ---------- Total 105,085 102,245 103,213 ---------- ---------- ---------- Net Income 190,513 193,676 194,716 Dividends On Preferred Stock 10,468 9,882 6,992 ---------- ---------- ---------- Net Income Applicable To Common Stock $ 180,045 $ 183,794 $ 187,724 ---------- ---------- ---------- ---------- ---------- ----------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. - 25 - CONSOLIDATED BALANCE SHEET
December 31 ---------------------- (Thousands of Dollars) 1994 1993 - ------------------------------------------------------------------------------------------ ASSETS Utility Plant - at original cost $5,613,013 $5,422,549 Less Accumulated Depreciation 2,400,601 2,205,043 Utility plant - net 3,212,412 3,217,506 Current Assets: Cash and cash equivalents 57,531 14,533 Accounts receivable - trade (less allowance for doubtful receivables of $10,830 in 1994 and $16,745 in 1993) 523,975 503,308 Regulatory accounts receivable - net 360,479 443,718 Gas in storage 63,470 53,114 Materials and supplies 25,792 20,618 Prepaid expense 34,129 22,971 ---------- ---------- Total current assets 1,065,376 1,058,262 ---------- ---------- Regulatory Assets 497,975 674,452 ---------- ---------- Total $4,775,763 $4,950,220 ---------- ---------- ---------- ---------- CAPITALIZATION AND LIABILITIES Capitalization: Common equity: Common stock $ 834,889 $ 834,889 Retained earnings 643,040 607,250 Total common equity 1,477,929 1,442,139 Preferred stock 196,551 196,551 Long-term debt 1,396,931 1,235,622 ---------- ---------- Total capitalization 3,071,411 2,874,312 ---------- ---------- Current Liabilities: Short-term debt 278,201 267,000 Accounts payable - trade 212,888 188,484 Accounts payable - affiliates 35,013 513,306 Accounts payable - other 143,235 228,517 Accrued taxes and franchise payments 117,576 21,907 Deferred income taxes 40,792 39,542 Long-term debt due within one year 86,000 Accrued interest 40,057 35,007 Other accrued liabilities 162,489 129,372 ---------- ---------- Total current liabilities 1,116,251 1,423,135 ---------- ---------- Customer Advances For Construction 44,269 45,493 Deferred Income Taxes 341,149 399,535 Deferred Investment Tax Credits 69,969 72,993 Other Deferred Credits 132,714 134,752 Commitments And Contingent Liabilities ---------- ---------- Total $4,775,763 $4,950,220 ---------- ---------- ---------- ----------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - 26 - STATEMENT OF CONSOLIDATED CASH FLOWS
Year Ended December 31 ---------------------------------- (Thousands of Dollars) 1994 1993 1992 - --------------------------------------------------------------------------------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net Income $190,513 $193,676 $194,716 Items not requiring cash: Depreciation 233,580 228,244 219,011 Deferred income taxes (49,432) 33,093 16,381 Deferred investment tax credits (3,024) (3,811) (3,616) Allowance for funds used during construction (3,757) (7,147) (5,904) Other (18,983) 22,442 24,258 Net change in other working capital components: Accounts receivable (20,667) (3,235) 40,794 Regulatory accounts receivable 231,006 (107,320) (107,203) Gas in storage (10,356) (13,279) 17,764 Other current assets (16,332) 19,787 37,432 Accounts payable (521,172) 77,672 (139,000) Accrued taxes and franchise payments 30,386 (74,466) 25,965 Deferred income taxes - current 4,914 23,501 13,719 Other current liabilities 103,451 26,245 (7,693) -------- -------- -------- Net cash provided by operating activities 150,127 415,402 326,624 -------- -------- -------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures for utility plant (244,721) (318,429) (326,085) (Increase) Decrease in other assets - net 35,267 (52,929) (7,856) -------- -------- -------- Net cash used in investing activities (209,454) (371,358) (333,941) -------- -------- -------- CASH FLOWS FROM FINANCING ACTIVITIES: Dividends (154,723) (144,590) (133,861) Issuance of long-term debt 245,847 631,000 282,000 Payments of long-term debt (569,239) (272,626) Sale of preferred stock 75,000 Redemption of preferred stock (75,000) Increase in short-term debt 11,201 52,000 92,000 -------- -------- -------- Net cash provided by (used in) financing activities 102,325 (30,829) (32,487) -------- -------- -------- Increase (Decrease) In Cash And Cash Equivalents 42,998 13,215 (39,804) Cash And Cash Equivalents - January 1 14,533 1,318 41,122 -------- -------- -------- Cash And Cash Equivalents - December 31 $ 57,531 $ 14,533 $ 1,318 -------- -------- -------- -------- -------- -------- SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash Paid During The Year For: Interest (net of amount capitalized) $107,088 $ 97,514 $ 11,574 -------- -------- -------- -------- -------- -------- Income taxes $ 89,135 $142,346 $105,241 -------- -------- -------- -------- -------- --------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - 27 - STATEMENT OF CONSOLIDATED SHAREHOLDERS' EQUITY
Preferred Common Retained (Thousands of Dollars) Stock Stock Earnings - ----------------------------------------------------------------------------- BALANCE AT DECEMBER 31, 1991 $196,551 $834,889 $498,569 Net income 194,716 Cash dividends declared: Preferred stock (6,992) Common stock (126,801) -------- -------- -------- BALANCE AT DECEMBER 31, 1992 196,551 834,889 559,492 Net income 193,676 Cash dividends declared: Preferred stock (9,882) Common stock (136,036) Preferred stock sold (3,000,000 shares) 75,000 Preferred stock redeemed (750 shares) (75,000) -------- -------- -------- BALANCE AT DECEMBER 31, 1993 196,551 834,889 607,250 Net income 190,513 Cash dividends declared: Preferred stock (10,468) Common stock (144,255) -------- -------- -------- BALANCE AT DECEMBER 31, 1994 $196,551 $834,889 $643,040 -------- -------- -------- -------- -------- --------
The number of shares of preferred stock and common stock authorized and outstanding at December 31, 1994 and 1993, is set forth in Note 9 of Notes to Consolidated Financial Statements. SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS. - 28 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Southern California Gas Company (the "Company") is a subsidiary of Pacific Enterprises ("Parent"). The Parent owns approximately 96 percent of the Company's voting stock, including all of its issued and outstanding common stock; therefore, per share data have been omitted. PRINCIPLES OF CONSOLIDATION The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiary, Southern California Gas Tower. The subsidiary has a 15 percent limited partnership interest in a 52-story office building in which the Company occupies approximately one-half of the leasable space. Investments in 50 percent or less joint ventures and partnerships are accounted for by the equity or cost method, as appropriate. RECLASSIFICATIONS Certain changes in account classification have been made in the prior years' consolidated financial statements to conform to the 1994 financial statement presentation. REGULATION The Company is a public utility and follows accounting policies prescribed or authorized by the California Public Utilities Commission (CPUC). The Company applies the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation." This statement requires cost-based rate regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. GAS IN STORAGE Gas in storage inventory is stated at last-in, first-out (LIFO) cost. As a result of the regulatory accounting procedure, the pricing of gas in storage does not have any effect on net income. If the first-in, first-out (FIFO) method of accounting for gas in storage inventory had been used by the Company, inventory would have been higher than reported at December 31, 1994 and 1993 by $34 million and $58 million, respectively. Materials and supplies are generally stated at the lower of cost, determined on an average cost basis, or market. UTILITY PLANT The cost of additions, renewals and improvements to utility plant are charged to the appropriate plant accounts. These costs include labor, material, other direct costs, indirect charges and an allowance for funds used during construction. The cost of utility plant retired or otherwise disposed of, plus removal costs and less salvage, is charged to accumulated depreciation. Depreciation is recorded on the straight-line remaining life basis. REGULATORY ACCOUNTS RECEIVABLE - NET Authorized regulatory balancing accounts are maintained to accumulate undercollections and overcollections from the revenue and cost estimates adopted by the CPUC in setting rates. The Company makes periodic filings with the CPUC to adjust future gas rates to account for such variances. - 29 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC) AFUDC represents the cost of funds used to finance the construction of utility plant and is added to the cost of utility plant. Interest expense of $4 million in 1994, $7 million in 1993 and $6 million in 1992 was capitalized. OTHER Cash equivalents include short-term investments purchased with maturities of less than 90 days. Other major accounting policies are included in the following notes. 2. REGULATORY MATTERS RESTRUCTURING OF GAS SUPPLY CONTRACTS In 1993, the Company and its gas supply affiliates restructured long-term gas supply contracts with suppliers of California offshore and Canadian gas. In the past, the Company's cost of these supplies had been substantially in excess of its average delivered cost of gas for all gas supplies. The restructured contracts substantially reduced the ongoing delivered costs of these gas supplies and provided lump sum payments totaling $391 million to the suppliers. The expiration date for the Canadian gas supply contract was also shortened from 2012 to 2003. COMPREHENSIVE SETTLEMENT OF REGULATORY ISSUES On July 20, 1994, the CPUC approved a comprehensive settlement (Comprehensive Settlement) of a number of pending regulatory issues including rate recovery of a significant portion of the restructuring costs associated with long-term gas supply contracts discussed above. The Comprehensive Settlement permits the Company to recover in utility rates approximately 80 percent of the contract restructuring costs of $391 million and accelerated amortization of related pipeline assets of approximately $140 million, together with interest, over a period of approximately five years. In addition to the gas supply issues, the Comprehensive Settlement addresses the following other regulatory issues: NONCORE CUSTOMER RATES. The Comprehensive Settlement changed the procedures for determining noncore rates to be charged by the Company to its customers for the five-year period commencing August 1, 1994. Rates charged to the customers are established based upon the Company's recorded throughput to these customers for 1991. The Company will bear the full risk of any declines in noncore deliveries from 1991 levels. Any revenue enhancement from deliveries in excess of 1991 levels will be limited by a crediting account mechanism that will require a credit to customers of 87.5 percent of revenues in excess of certain limits. These annual limits above which the credit is applicable increase from $11 million to $19 million over the five-year period from August 1, 1994 through July 31, 1999. The Company's ability to report as earnings the results from revenues in excess of its authorized return from noncore customers due to volume increases has been substantially eliminated for the five years beginning August 1, 1994 as a consequence of the Comprehensive Settlement described above. This is because forecasted deliveries in excess of the 1991 throughput levels used to establish noncore rates were contemplated in estimating the costs of the Comprehensive Settlement at December 31, 1993. - 30 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS REASONABLENESS REVIEWS. The Comprehensive Settlement includes settlement of all pending reasonableness reviews with respect to the Company's gas purchases from April, 1989 through March, 1992 as well as certain other future reasonableness review issues. The Comprehensive Settlement also allows recovery of future excess interstate pipeline capacity costs in the Company's rates. GAS COST INCENTIVE MECHANISM. On March 16, 1994, the CPUC approved a new process for evaluating the Company's gas purchases, substantially replacing the previous process of reasonableness reviews. The new Gas Cost Incentive Mechanism (GCIM) is a three-year pilot program beginning April 1, 1994. The GCIM essentially compares the Company's cost of gas with a benchmark level, which is the average market price of 30-day firm spot supplies delivered to the Company's service area. All savings from gas purchased below the benchmark are shared equally between ratepayers and shareholders. The Company can recover all costs in excess of the benchmark but within a tolerance band. If the Company's cost of gas exceeds the tolerance band, then the excess costs will be shared equally between ratepayers and shareholders. For the first year of the program, the GCIM provides a 4.5 percent tolerance band above the benchmark. For the second and third years of the program, the tolerance band decreases to 4.0 percent. In 1994, since the inception of the GCIM, the Company's gas purchases were within the tolerance band (See Note 8). ATTRITION ALLOWANCES. The Comprehensive Settlement authorizes the Company annual allowances for operational attrition for 1995 and 1996 to the extent that the annual inflation rate for those years exceeds 2 percent and 3 percent, respectively, for operating and maintenance expenses. This compares to a 3 percent productivity adjustment authorized for 1994. The rate base attrition will continue based upon a three year rolling average of recorded net utility plant additions. This is a departure from past regulatory practice of allowing recovery of the full effect of inflation on operating and maintenance expenses in rates. The Company intends to continue to attempt to control operating expenses and investment in those years to amounts authorized in rates to offset the effect of this regulatory change. The Company recorded the impact of the Comprehensive Settlement in 1993 and, upon giving effect to liabilities previously recognized at the Company, the costs of the Comprehensive Settlement, including the restructuring of gas supply contracts, did not result in any additional charge to the Company's consolidated earnings. Regulatory Accounts Receivable-Net and Regulatory Assets include a total of approximately $327 million and $465 million in 1994 and 1993 respectively, for the recovery of costs as provided in the Comprehensive Settlement. At December 31, 1993, Accounts Payable-Other included the remaining liability for settlement payments of $375 million, which were paid in 1994, to restructure the long-term gas supply contracts. The CPUC authorized the borrowing of up to $425 million primarily to provide for funds needed under the Comprehensive Settlement. As of December 31, 1994, the Company has $524 million in commercial paper outstanding, of which $330 million relates to the Comprehensive Settlement (See Note 6). - 31 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. INCOME TAXES In 1992, the Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," the effect of which was not material to the financial statements. A reconciliation of the difference between computed statutory federal income tax expense and actual income tax expense is as follows:
Year Ended December 31 ------------------------------- (Thousands of Dollars) 1994 1993 1992 - ------------------------------------------------------------------------------- Computed statutory federal income tax expense $117,311 $112,874 $121,935 Increase (reductions) resulting from: Excess book over tax depreciation 17,473 17,847 17,121 State income taxes - net of federal income tax benefit 19,119 16,993 23,543 Capitalized expenses not deferred (6,589) Federal income tax rate change 1,698 Research and development credit (4,000) Amortization of deferred investment tax credits (3,024) (3,811) (3,867) Resolution of proposed tax deficiency 3,850 (10,193) Other - net (3,478) (2,587) 5,183 ------------------------------ Total income tax expense $144,662 $128,821 $163,915 ------------------------------ ------------------------------
The components of income tax expense are as follows:
Year Ended December 31 ------------------------------- (Thousands of Dollars) 1994 1993 1992 - ------------------------------------------------------------------------------- Federal Current $147,647 $ 53,831 $103,908 Deferred (32,500) 46,044 25,254 ------------------------------- 115,147 99,875 129,162 ------------------------------- ------------------------------- State Current 44,289 22,206 34,331 Deferred (14,774) 6,740 422 ------------------------------- 29,515 28,946 34,753 ------------------------------- ------------------------------- Total Current 191,936 76,037 138,239 Deferred (47,274) 52,784 25,676 ------------------------------- $144,662 $128,821 $163,915 ------------------------------- -------------------------------
- 32 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS The principal components of net deferred tax liabilities are as follows:
December 31 - ---------------------------------------------------------------------------------------------------------------------- 1994 1993 - ---------------------------------------------------------------------------------------------------------------------- (Thousands of Dollars) Assets Liabilities Total Assets Liabilities Total - ---------------------------------------------------------------------------------------------------------------------- Depreciation $(399,381) $(399,381) $(382,983) $(382,983) Comprehensive Settlement $211,996 211,996 Regulatory accounts receivable (150,767) (150,767) (162,339) (162,339) Deferred investment tax credits 30,996 30,996 $32,336 32,336 Customer advances for construction 25,527 25,527 21,774 21,774 Regulatory asset (39,604) (39,604) (44,873) (44,873) Other regulatory 109,084 (169,792) (60,708) 153,634 (56,626) 97,008 ------------------------------------------------------------------------------- Total deferred income tax assets (liabilities) $377,603 $(759,544) $(381,941) $207,744 $(646,821) $(439,077) ------------------------------------------------------------------------------- -------------------------------------------------------------------------------
The Parent files a consolidated federal income tax return and combined California franchise tax reports which include the Company and the Parent's other subsidiaries. The Company pays the amount of taxes applicable to itself had it filed a separate return. The Company generally provides for income taxes on the basis of amounts expected to be paid currently, except for the provision for deferred income taxes on regulatory accounts, customer advances for construction and accelerated depreciation of property placed in service after 1980. In addition, the Company recognizes certain other deferred tax liabilities (primarily accelerated depreciation of property placed in service prior to 1981 and deferred investment tax credits) which are expected to be recovered through future rates. At December 31, 1994 and 1993, $97 million and $109 million, respectively, of deferred income taxes have been offset by an equivalent amount in regulatory assets. 4. COMMITMENTS AND CONTINGENT LIABILITIES ENVIRONMENTAL OBLIGATIONS The Company has identified and reported to California environmental authorities 42 former manufactured gas plant sites for which it (together with other utilities as to 21 of the sites) may have environmental obligations under environmental laws. As of December 31, 1994, eight of these sites have been remediated, of which five have received certification from the California Environmental Protection Agency. Preliminary investigations, at a minimum, have been completed on 33 of the gas plant sites including those sites at which the remediations described above have been completed. In addition, the Company has been named as a potentially responsible party of one landfill site and three industrial waste disposal sites. On May 4, 1994, the CPUC approved a collaborative settlement between the Company and other California energy utilities and the Division of Ratepayer Advocates which provides for rate recovery of 90 percent of environmental investigation and remediation costs without reasonableness review. In addition, the utilities have the opportunity to retain a percentage of any insurance recoveries to offset the 10 percent of costs not recovered in rates. - 33 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS At December 31, 1994, the Company's estimated remaining investigation and remediation liability was approximately $65 million which it is authorized to recover through the mechanism discussed above. The estimated liability is subject to future adjustment pending further investigation. In 1993 and 1992, the Company charged $7 million and $5 million, respectively, to income and the remaining amount is included in Regulatory Assets. There were no related charges to income in 1994. The Company believes that any costs not ultimately recovered through rates, insurance or other means, upon giving effect to previously established liabilities, will not have a material adverse effect on the Company's financial statements. LITIGATION The Company is a defendant in various lawsuits arising in the normal course of business. Management believes that the resolution of these pending claims and legal proceedings will not have a material effect on the Company's financial statements. OTHER COMMITMENTS AND CONTINGENCIES At December 31, 1994, commitments for capital expenditures were approximately $33 million. On January 17, 1994, the Company's service area was struck by a major earthquake. The result was a disruption in service to 150,000, or less than 3 percent, of its customers and damage to some facilities. The financial impact of the damages related to the earthquake not recovered by insurance is expected to be recovered in rates under an existing balancing account mechanism, and should have no material effect on the Company's financial statements. 5. LEASES The Company has leases on real and personal property expiring at various dates from 1995 to 2011. The rentals payable under these leases are determined on both fixed and percentage bases and most leases contain options to extend which are exercisable by the Company. Rental expense under operating leases was $42 million, $39 million and $37 million, in 1994, 1993 and 1992, respectively. The following is a schedule of future minimum operating lease commitments as of December 31, 1994:
Future Minimum (Thousands of Dollars) Lease Payments - ----------------------------------------------------------------------------- Year Ending December 31: 1995 $ 30,345 1996 28,164 1997 29,427 1998 27,322 1999 27,161 Later years 314,341 -------- Total $456,760 -------- --------
- 34 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 6. COMPENSATING BALANCES AND SHORT-TERM BORROWING ARRANGEMENTS The Company has $750 million of unsecured revolving lines of credit, of which $350 million is a multi-year credit agreement requiring annual fees of .10 percent and $400 million is a 364 day credit agreement requiring annual fees of .07 percent. The interest rates on these lines vary and are derived from formulas based on market rates and the Company's credit rating. The multi-year credit agreement expires on February 8, 2000. At December 31, 1994, all bank lines of credit were unused. The unused bank lines of credit support the Company's commercial paper program and provide liquidity for the Company. At December 31, 1994 and 1993, the Company had $524 million and $267 million, respectively, of commercial paper obligations outstanding. The weighted average annual interest rate of commercial paper obligations outstanding was 5.96 percent and 3.25 percent at December 31, 1994 and 1993, respectively. At December 31, 1994, the Company has classified $246 million of the commercial paper as long-term debt since it is the Company's intent (supported by the $350 million multi-year credit agreement above) to continue to refinance that portion of the debt on a long-term basis. - 35 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 7. LONG-TERM DEBT
December 31 --------------------- (Thousands of Dollars) 1994 1993 - ----------------------------------------------------------------------------------------------------- FIRST MORTGAGE BONDS: 6 1/2 % December 15, 1997 $ 125,000 $ 125,000 5 1/4% March 1, 1998 100,000 100,000 6 7/8 % August 15, 2002 100,000 100,000 5 3/4% November 15, 2003 100,000 100,000 9 3/4 % December 1, 2020 18,435 18,435 8 3/4 % October 1, 2021 150,000 150,000 7 3/8 % March 1, 2023 100,000 100,000 7 1/2 % June 15, 2023 125,000 125,000 6 7/8 % November 1, 2025 175,000 175,000 OTHER LONG-TERM DEBT: 4.69% Notes, June 16, 1995 31,000 31,000 8 3/4% Notes, August 4, 1995 20,000 20,000 5.03% - 5.05% Notes, August 28 - September 1, 1995 28,000 28,000 5.81% - 5.85% Notes, December 1, 1995 7,000 7,000 8 3/4% Notes, July 8, 1996 20,000 20,000 5.98% Notes, August 28, 1997 22,000 22,000 8 3/4% Notes, July 6, 2000 10,000 10,000 SFr. 100,000,000 5 1/8 % Bonds, February 6, 1998 (foreign currency exposure hedged through currency swap at an interest rate of 9.725%) 47,250 47,250 SFr. 150,000,000 7 1/2 % Foreign Interest Payment Securities May 14, 1996 75,282 75,282 5.96% Commercial Paper, February 8, 2000 245,847 ----------------------- Total outstanding 1,499,814 1,253,967 ----------------------- Less: Payments due within one year 86,000 Unamortized debt discount less premium 16,883 18,345 ----------------------- 102,883 18,345 ----------------------- Long-Term Debt $1,396,931 $1,235,622 ----------------------- -----------------------
The annual principal payment requirements of long-term debt for the years 1995 through 1998 are $86 million, $95 million, $147 million, and $497 million, respectively. No amounts are due in 1999. Substantially all utility plant is pledged as collateral for the first mortgage bonds. CURRENCY RATE SWAPS In February 1986, the Company issued SFr. 100 million of 5 1/8 percent bonds which will mature on February 6, 1998. The Company has entered into a swap transaction with a major international bank to hedge the currency exposure. The terms of the swap result in a U.S. dollar liability of $47 million at an interest rate of 9.725 percent with the principal payable on February 6, 1998. In May 1986, the Company issued SFr. 150 million of 7 1/2 percent Foreign Interest Payment Securities which are renewable at 10-year intervals at reset interest rates. Interest is payable in U.S. dollars. The principal was exchanged into $75 million at an exchange rate of 1.9925, which is also the minimum rate of exchange for determining the amount of principal repayable in Swiss francs. - 36 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 8. FINANCIAL INSTRUMENTS The carrying amount of cash and cash equivalents approximates fair value because of the short maturity of those instruments. The Company's Flexible Auction Series preferred stocks approximate fair value since they are remarketed periodically. The fair value of the Company's long-term debt, 6 percent preferred, 6 percent Series A preferred and 7 3/4 percent preferred stock is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of similar remaining maturities. The fair value of the currency rate swap is the estimated amount that the bank would receive or pay to terminate the swap agreement at the reporting date, taking into account current exchange rates and the current credit worthiness of the swap counterparty. The fair value of these financial instruments is different from the carrying amount. The following financial instruments have a fair value which is different from the carrying amount as of December 31.
1994 1993 ------------------------------------- (Dollars Carrying Fair Carrying Fair in Millions) Amount Value Amount Value - ------------------------------------------------------------------ Long-Term Debt $1,499 $1,377 $1,253 $1,272 Preferred Stocks $ 97 $ 78 $ 97 $ 95
In October, 1994, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards No. 119 (SFAS 119), "Disclosure about Derivative Financial Instruments and Fair Value of Financial Instruments." SFAS 119 is effective for financial statements issued for fiscal years ending after December 15, 1994 and requires certain disclosures about financial instruments not covered by SFAS 105, "Disclosure of Information about Financial Instruments with Off-Balance Sheet Risk and Financial Instruments with Concentrations of Credit Risk." As a result of the Gas Cost Incentive Mechanism (GCIM) (See Note 2), the Company enters into a certain amount of gas futures contracts in the open market to help reduce gas costs within the GCIM tolerance band. The Company's policy is to use gas futures contracts to mitigate risk and better manage gas costs. The CPUC has approved the use of gas futures for managing risk associated with the GCIM. For the year ended December 31, 1994, gains or losses from gas futures contracts are not material to the Company's financial statements. - 37 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 9. CAPITAL STOCK The amount of capital stock outstanding is as follows:
December 31, 1994 December 31, 1993 ---------------------------------------------- Number Thousands Number Thousands of Shares of Dollars of Shares of Dollars ---------------------------------------------- PREFERRED STOCK: cumulative, voting (a) (b) (c) (d): 6%, $25 par value 79,011 $ 1,975 79,011 $ 1,975 6%, Series A, $25 par value 783,032 19,576 783,032 19,576 Series Preferred, no par value: Flexible Auction, Series A 500 50,000 500 50,000 Flexible Auction, Series C 500 50,000 500 50,000 7 3/4%, $25 Stated Value 3,000,000 75,000 3,000,000 75,000 -------- -------- Total $196,551 $196,551 -------- -------- -------- -------- PREFERENCE STOCK - cumulative, voting, no par value (a) (c) COMMON STOCK - no par value (a) (c) 91,300,000 $834,889 91,300,000 $834,889 -------- -------- -------- --------
(a) The Company's Articles of Incorporation authorize the following stocks: 100 million shares of Common Stock; 160,000 shares of 6% Preferred Stock; 840,000 shares of 6% Preferred Stock, Series A; 5 million shares of Series Preferred Stock and 5 million shares of Preference Stock. (b) Each issue of the Flexible Auction Series Preferred Stock is auctioned on specified dividend dates. The term of each subsequent dividend period is, at the Company's option, 49 days or longer, not to exceed ten years. The weighted average dividend rates for the Flexible Auction Series Preferred Stock for 1994, 1993 and 1992 were: Series A, 3.40 percent, 2.67 percent and 3.21 percent, respectively; and Series C, 3.33 percent, 2.75 percent and 3.28 percent, respectively. Subsequent dividend rates may be affected by general market conditions and the credit rating assigned to the Flexible Auction Series Preferred Stock. The Company has the option of redeeming the shares, in whole or in part, at $100,000 per share plus accumulated dividends, on any scheduled dividend payment date. (c) In the event of any liquidation, dissolution or winding up of the Company, the holders of shares of each series of Preferred Stock and of each series of Series Preferred Stock would be entitled to receive the stated value or the liquidation preference for their shares, plus accrued dividends before any amount shall be paid to the holders of Preference Stock or Common Stock. If the amounts payable with respect to the shares of each series of Preferred Stock or Series Preferred Stock are not paid in full, the holders of such shares will share ratably in any such distribution. After payment in full to the holders of each series of Preferred Stock, Series Preferred Stock and Preference Stock of the liquidating distributions to which they are entitled, the remaining assets and funds of the Company would be divided pro rata among the holders of the 6% Preferred Stock and the holders of Common Stock. - 38 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 10. TRANSACTIONS WITH AFFILIATES Pacific Interstate Transmission Company, Pacific Interstate Offshore Company and Pacific Offshore Pipeline Company, subsidiaries of the Parent and gas supply affiliates of the Company, sell and transport gas to the Company under tariffs approved by the Federal Energy Regulatory Commission. During 1994, 1993 and 1992, billings for such gas purchases totaled $215 million, $344 million, and $356 million, respectively. The Company has long-term gas purchase and transportation agreements with the affiliates extending through the year 2003 requiring certain minimum payments which allow the affiliates to recover the construction cost of their facilities. The Company is obligated to make minimum annual payments to cover the affiliates' operation and maintenance expenses, demand charges paid to their suppliers, current taxes other than income taxes, and debt service costs, including interest expense and scheduled retirement of debt. These long-term agreements were restructured in conjunction with the Comprehensive Settlement previously discussed (see Note 2). 11. PENSION, POSTRETIREMENT AND OTHER EMPLOYEE BENEFIT PLANS PENSION PLAN The Company has a noncontributory defined benefit pension plan covering substantially all of its employees. Benefits are based on employees' years of service and compensation during their last years of employment. The Company's policy is to fund the plan annually at a level which is fully deductible for federal income tax purposes and as necessary on an actuarial basis to provide assets sufficient to meet the benefits to be paid to plan members. In conformity with generally accepted accounting principles for a rate regulated enterprise, the Company has recorded regulatory adjustments to reflect, in net income, pension costs calculated under the actuarial method allowed for ratemaking. The cumulative difference between the net periodic pension cost calculated for financial reporting and ratemaking purposes has been included as a deferred charge or credit in the Consolidated Balance Sheet. Pension expense is as follows:
Year Ended December 31 --------------------------------------- (Thousands of Dollars) 1994 1993 1992 - ------------------------------------------------------------------------------------------------- Service cost - benefits earned during the period $33,627 $31,828 $30,327 Interest cost on projected benefit obligation 80,741 78,727 75,578 Actual return on plan assets (2,631) (153,293) (68,730) Net amortization and deferral (94,173) 54,816 (13,041) ------------------------------------- Net periodic pension cost 17,564 12,078 24,134 Special early retirement program 11,790 17,546 12,227 Postretirement health care and life insurance benefits 22,088 Regulatory adjustment (1,878) 919 (8,891) ------------------------------------- Total pension expense $27,476 $30,543 $49,558 ------------------------------------- -------------------------------------
-39 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS A reconciliation of the pension plan's funded status to the pension liability recognized in the Consolidated Balance Sheet is as follows:
December 31 -------------------------- (Thousands of Dollars) 1994 1993 - ------------------------------------------------------------------------------------------------------- Actuarial present value of pension benefit obligations Accumulated benefit obligation, including $751,852 and $792,800 in vested benefits at December 31, 1994 and 1993, respectively $ 844,762 $ 907,890 Effect of future salary increases 203,995 267,061 - ------------------------------------------------------------------------------------------------------- Projected benefit obligation 1,048,757 1,174,951 Less: plan assets at fair value, primarily publicly traded common stocks and equity pooled funds (1,237,747) (1,282,921) Unrecognized net gain 234,372 157,215 Unrecognized prior service cost (35,761) (39,480) Unrecognized transition obligation (5,143) (5,658) - ------------------------------------------------------------------------------------------------------- Accrued pension liability included in the Consolidated Balance Sheet $ 4,478 $ 4,107 - ------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------- Deferred pension credit (charge) included in the Consolidated Balance Sheet $ (1,489) $ 390 - ------------------------------------------------------------------------------------------------------- - ------------------------------------------------------------------------------------------------------- The plan's major actuarial assumptions include: Weighted average discount rate 8% 7% Rate of increase in future compensation levels 5% 5% Expected long-term rate of return on plan assets 8% 8 1/2%
POSTRETIREMENT BENEFIT PLAN In 1993, the Company adopted Statement of Financial Accounting Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106). SFAS 106 requires the accrual of the cost of certain postretirement benefits other than pensions over the active service period of the employee. The Company previously recorded these costs when paid or funded. In accordance with SFAS 106, the Company elected to amortize the unfunded transition obligation of $256 million over 20 years. The CPUC in late 1992 authorized SFAS 106 amounts to be recovered in rates. As with pensions, the Company has recorded regulatory adjustments to reflect, in net income, postretirement benefit costs calculated under the actuarial method allowed for ratemaking. The cumulative difference between the net periodic postretirement benefit cost calculated for financial reporting and ratemaking purposes has been included as a deferred charge or credit in the Consolidated Balance Sheet. The Company's postretirement benefit plan currently provides medical and life insurance benefits to qualified retirees. In the past, employee cost-sharing provisions have been implemented to control the increasing costs of these benefits. Other changes could occur in the future. The Company's policy is to fund these benefits at a level which is fully tax deductible for federal income tax purposes, not to exceed amounts recoverable in rates, and as necessary on an actuarial basis to provide assets sufficient to be paid to plan participants. The net postretirement benefit expense was as follows: - 40 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Year Ended December 31 ---------------------- (Thousands of Dollars) 1994 1993 - -------------------------------------------------------------------------- Service cost - benefits earned during the period $13,122 $11,917 Interest cost on projected benefit obligation 26,464 26,848 Actual return on plan assets (1,487) (10,076) Net amortization and deferral 2,561 15,205 ------------------- Net periodic postretirement benefit cost 40,660 43,894 Regulatory adjustment (2,887) ------------------- Net postretirement benefit expense $37,773 $43,894 ------------------- -------------------
Prior to 1993, the Company commenced funding its future liability for postretirement benefits through the pension plan. Amounts funded were subject to the respective income tax limitations and amounts provided through rates. In 1992, the amounts funded totaled $22 million. A reconciliation of the plan's funded status to the postretirement benefit liability recognized in the Consolidated Balance Sheet is as follows:
December 31 ------------------ (Thousands of Dollars) 1994 1993 - ------------------------------------------------------------------------ Accumulated postretirement benefit obligation: Retirees $160,066 $147,666 Fully eligible active plan participants 174,440 178,777 Other active plan participants 17,012 30,799 ------------------ 351,518 357,242 Less: plan assets at fair value, primarily publicly traded common stocks and equity pooled funds (144,304) (116,803) Unrecognized net transition obligation (230,047) (242,827) Unrecognized net gain 19,954 1,365 ------------------ Prepaid postretirement benefit asset included in the Consolidated Balance Sheet $ (2,879) $ (1,023) ------------------ ------------------ Deferred postretirement benefit charge included in the Consolidated Balance Sheet $ (2,887) $ 0 ------------------ ------------------ The plan's major actuarial assumptions include: Health care cost trend rate 8% 8% Weighted average discount rate 8% 7% Rate of increase in future compensation levels 5% 5% Expected long-term rate of return on plan assets 8% 8 1/2%
The assumed health care cost trend rate is 7.5 percent for 1995. The trend rate is expected to decrease from 1995 to 1998 with a 6 percent ultimate trend rate thereafter. The effect of a one-percentage-point increase in the assumed health care cost trend rate for each future year is $7.1 million on the aggregate of the service and interest cost components of net periodic postretirement cost for 1994 and $54.4 million on the accumulated postretirement benefit obligation at December 31, 1994. The estimated income tax rate used in the return on plan assets is zero since the plan is tax exempt. - 41 - NOTES TO CONSOLIDATED FINANCIAL STATEMENTS POSTEMPLOYMENT BENEFITS Effective January 1, 1994, the Company adopted SFAS 112, "Employers' Accounting for Postemployment Benefits". SFAS 112 requires the accrual of the obligation to provide benefits to former or inactive employees after employment but before retirement. The adoption of SFAS 112 had no impact on earnings since these costs are currently recovered in rates as paid, and as such, have been reflected as a regulatory asset. At December 31, 1994 and 1993, the total postemployment benefit liability was $49 million and $39 million, respectively, and represents primarily workers' compensation and disability benefits. EARLY RETIREMENT PROGRAM In 1994 and 1993, the Company offered a special early retirement program for a limited period to certain eligible employees. The cost of this program is included in the total pension expense for 1994 and 1993, respectively. RETIREMENT SAVINGS PLAN Upon completion of one year of service, all employees of the Company are also eligible to participate in the Company's retirement savings plan administered by bank trustees. Employees may contribute from 1 to 14 percent of their regular earnings. The Company generally contributes an amount of cash or a number of shares of the Parent's common stock of equivalent fair market value which, when added to prior forfeitures, will equal 50 percent of the first 6 percent of eligible base salary contributed by employees. The employees' contributions, at the direction of the employees, are primarily invested in the Parent's common stock, mutual funds or guaranteed investment contracts. The Company's contributions, which were invested in the Parent's common stock, were $8 million in 1994 and $9 million each in 1993 and 1992. - 42 - STATEMENT OF MANAGEMENT RESPONSIBILITY FOR CONSOLIDATED FINANCIAL STATEMENTS The consolidated financial statements have been prepared by management. The integrity and objectivity of these financial statements and the other financial information in the Annual Report, including the estimates and judgments on which they are based, are the responsibility of management. The financial statements have been audited by Deloitte & Touche LLP, independent certified public accountants, appointed by the Board of Directors. Their report is shown on the following page. Management has made available to Deloitte & Touche LLP all of the Company's financial records and related data, as well as the minutes of shareholders' and directors' meetings. Management maintains a system of internal accounting control which it believes is adequate to provide reasonable, but not absolute, assurance that assets are properly safeguarded and accounted for, that transactions are executed in accordance with management's authorization and are properly recorded and reported, and for the prevention and detection of fraudulent financial reporting. Management monitors the system of internal control for compliance through its own review and a strong internal auditing program which also independently assesses the effectiveness of the internal controls. In establishing and maintaining internal controls, the Company exercises judgment in determining that the costs of such controls do not exceed the benefits to be derived. Management acknowledges its responsibility to provide financial information (both audited and unaudited) that is representative of the Company's operations, reliable on a consistent basis, and relevant for a meaningful financial assessment of the Company. Management believes that the control process enables them to meet this responsibility. Management also recognizes its responsibility for fostering a strong ethical climate so that the Company's affairs are conducted according to the highest standards of personal and corporate conduct. This responsibility is characterized and reflected in the Parent's code of corporate conduct, which is publicized throughout the Company. The Parent maintains a systematic program to assess compliance with this policy. The Board of Directors has an Audit Committee composed solely of directors who are not officers or employees of the Company. The Committee recommends for approval by the full Board the appointment of the independent auditors. The Committee meets regularly with management, with the Company's internal auditors and with the independent auditors. The independent auditors and the internal auditors periodically meet alone with the Audit Committee and have free access to the Audit Committee at any time. Warren I. Mitchell, President Ralph Todaro, Vice President and Controller January 31, 1995 - 43 - INDEPENDENT AUDITORS' REPORT Southern California Gas Company: We have audited the consolidated financial statements of Southern California Gas Company and its subsidiaries (pages 25 to 42) as of December 31, 1994 and 1993, and for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Southern California Gas Company and its subsidiaries as of December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. DELOITTE & TOUCHE LLP Los Angeles, California January 31, 1995 - 44 - OTHER INFORMATION QUARTERLY FINANCIAL DATA (UNAUDITED)
1994 -------------------------------------- Three Months Ended March 31 June 30 Sept. 30 Dec. 31 - ------------------------------------------------------------------------- (Thousands of Dollars) Operating revenues $689,154 $630,298 $567,929 $699,143 Net operating revenue $ 67,598 $ 68,094 $ 67,575 $ 75,360 Net income $ 43,949 $ 45,788 $ 45,197 $ 55,579 Net income applicable to Common stock $ 41,509 $ 43,223 $ 42,532 $ 52,781 1993 -------------------------------------- Three Months Ended March 31 June 30 Sept. 30 Dec. 31 - ------------------------------------------------------------------------- (Thousands of Dollars) Operating revenues $758,721 $633,440 $625,172 $793,741 Net operating revenue $ 70,602 $ 68,847 $ 75,270 $ 69,779 Net income $ 46,167 $ 47,462 $ 50,064 $ 49,983 Net income applicable to common stock $ 43,634 $ 45,025 $ 47,622 $ 47,513
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. - 45 - PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT Information required by this Item with respect to the Company's directors is set forth under the caption "Election of Directors" in the Company's Information Statement for its Annual Meeting of Shareholders scheduled to be held on May 2, 1995. Such information is incorporated herein by reference. Information required by this Item with respect to the Company's executive officers is set forth in Item 1 of this Annual Report. ITEM 11. EXECUTIVE COMPENSATION Information required by this Item is set forth under the caption "Election of Directors" and "Executive Compensation" in the Company's Information Statement for its Annual Meeting of Shareholders scheduled to be held on May 2, 1995. Such information is incorporated herein by reference. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT Information required by this Item is set forth under the caption "Election of Directors" in the Company's Information Statement for its Annual Meeting of Shareholders scheduled to be held on May 2, 1995. Such information is incorporated herein by reference. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS Not applicable. - 46 - PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) Documents filed as part of this report: 1. CONSOLIDATED FINANCIAL STATEMENTS (SET FORTH IN ITEM 8 OF THIS ANNUAL REPORT ON FORM 10-K): 1.01 Report of Deloitte & Touche LLP, Independent Certified Public Accountants. 1.02 Statement of Consolidated Income for the years ended December 31, 1994, 1993 and 1992. 1.03 Consolidated Balance Sheet at December 31, 1994 and 1993. 1.04 Statement of Consolidated Cash Flows for the years ended December 31, 1994, 1993 and 1992. 1.05 Statement of Consolidated Shareholders' Equity for the years ended December 31, 1994, 1993, 1992 and 1991. 1.06 Notes to Consolidated Financial Statements. 3. ARTICLES OF INCORPORATION AND BY-LAWS: 3.01 Restated Articles of Incorporation of Southern California Gas Company (Note 25; Exhibit 3.01). 3.02 Bylaws of Southern California Gas Company. 4. INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS: (Note: As permitted by Item 601(b)(4)(iii) of Regulation S-K, certain instruments defining the rights of holders of long-term debt for which the total amount of securities authorized thereunder does not exceed ten percent of the total assets of Southern California Gas Company and its subsidiaries on a consolidated basis are not filed as exhibits to this Annual Report. The Company agrees to furnish a copy of each such instrument to the Commission upon request.) 4.01 Specimen Preferred Stock Certificates of Southern California Gas Company (Note 13; Exhibit 4.01). - 47 - 4.02 First Mortgage Indenture of Southern California Gas Company to American Trust Company dated as of October 1, 1940 (Note 1; Exhibit B-4). 4.03 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of July 1, 1947 (Note 2; Exhibit B-5). 4.04 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of August 1, 1955 (Note 3; Exhibit 4.07). 4.05 Supplemental Indenture of Southern California Gas Company to American Trust Company dated as of June 1, 1956 (Note 4; Exhibit 2.08). 4.06 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of August 1, 1972 (Note 7; Exhibit 2.19). 4.07 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of May 1, 1976 (Note 6; Exhibit 2.20). 4.08 Supplemental Indenture of Southern California Gas Company to Wells Fargo Bank, National Association dated as of September 15, 1981 (Note 12; Exhibit 4.25). 4.09 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 (Note 16; Exhibit 4.29). 4.10 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 (Note 18; Exhibit 4.11). 4.11 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 (Note 24; Exhibit 4.37). 4.12 Specimen Flexible Auction Series A Preferred Stock Certificate (Note 21; Exhibit 4.11). - 48 - 4.13 Specimen Flexible Auction Series B Preferred Stock Certificate (Note 22; Exhibit 4.12). 4.14 Specimen Flexible Auction Series C Preferred Stock Certificate (Note 23; Exhibit 4.13). 4.15 Specimen 7 3/4% Series Preferred Stock Certificate (Note 25; Exhibit 4.15). 10. MATERIAL CONTRACTS 10.01 Restatement and Amendment of Pacific Enterprises 1979 Stock Option Plan (Note 10; Exhibit 1.1). 10.02 Pacific Enterprises Supplemental Medical Reimbursement Plan for Senior Officers (Note 11; Exhibit 10.24). 10.03 Pacific Enterprises Financial Services Program for Senior Officers (Note 11; Exhibit 10.25). 10.04 Southern California Gas Company Retirement Savings Plan, as amended and restated as of August 30, 1988 (Note 15; Exhibit 28.02). 10.05 Southern California Gas Company Statement of Life Insurance, Disability Benefit and Pension Plans, as amended and restated as of January 1, 1985 (Note 16; Exhibit 10.27). 10.06 Southern California Gas Company Pension Restoration Plan For Certain Management Employees (Note 11; Exhibit 10.29). 10.07 Pacific Enterprises Executive Incentive Plan (Note 18; Exhibit 10.13) 10.08 Pacific Enterprises Deferred Compensation Plan for Key Management Employees (Note 15; Exhibit 10.41). 10.09 Pacific Enterprises Stock Incentive Plan (Note 19; Exhibit 4.01). 10.10 Pacific Enterprises Employee Stock Option Plan (Note 27; Exhibit 4.01). 21. SUBSIDIARIES OF THE REGISTRANT 21.01 List of subsidiaries of Southern California Gas Company. - 49 - 23. CONSENTS OF EXPERTS AND COUNSEL 23.01 Consent of Deloitte & Touche LLP, Independent Certified Public Accountants. 24. POWER OF ATTORNEY 24.01 Power of Attorney of Certain Officers and Directors of Southern California Gas Company (contained on the signature pages of this Annual Report on Form 10-K). 27. Financial Data Schedule 27.01 Financial Data Schedule (b) REPORTS ON FORM 8-K: The following report on Form 8-K was filed during the last quarter of 1994. REPORT DATE ITEM REPORTED Nov. 23, 1994 Item 5 NOTE: Exhibits referenced to the following notes were filed with the documents cited below under the exhibit or annex number following such reference. Such exhibits are incorporated herein by reference. -50- Note REFERENCE DOCUMENT 1 Registration Statement No. 2-4504 filed by Southern California Gas Company on September 16, 1940. 2 Registration Statement No. 2-7072 filed by Southern California Gas Company on March 15, 1947. 3 Registration Statement No. 2-11997 filed by Pacific Lighting Corporation on October 26, 1955. 4 Registration Statement No. 2-12456 filed by Southern California Gas Company on April 23, 1956. 5 Registration Statement No. 2-45361 filed by Southern California Gas Company on August 16, 1972. 6 Registration Statement No. 2-56034 filed by Southern California Gas Company on April 14, 1976. 7 Registration Statement No. 2-59832 filed by Southern California Gas Company on September 6, 1977. 8 Registration Statement No. 2-42239 filed by Pacific Lighting Gas Supply Company (under its former name of Pacific Lighting Service Company) on October 29, 1971. 9 Registration Statement No. 2-43834 filed by Pacific Lighting Corporation on April 17, 1972. 10 Registration Statement No. 2-66833 filed by Pacific Lighting Corporation on March 5, 1980. 11 Annual Report on Form 10-K for the year ended December 31, 1980, filed by Pacific Lighting Corporation. 12 Annual Report on Form 10-K for the year ended December 31, 1981, filed by Pacific Lighting Corporation. 13 Annual Report on Form 10-K for the year ended December 31, 1980 filed by Southern California Gas Company. 14 Quarterly Report on Form 10-Q for the quarter ended September 30, 1983, filed by Southern California Gas Company. 15 Registration Statement No. 33-6357 filed by Pacific Enterprises on December 30, 1988. 16 Annual Report on Form 10-K for the year ended December 31, 1984, filed by Southern California Gas Company. 17 Current Report on Form 8-K for the month of March 1986, filed by Southern California Gas Company. - 51 - 18 Annual Report on Form 10-K for the year ended December 31, 1987 filed by Pacific Lighting Corporation. 19 Registration Statement No. 33-21908 filed by Pacific Enterprises on May 17, 1988. 20 Annual Report on Form 10-K for the year ended December 31, 1988, filed by Southern California Gas Company. 21 Annual Report on Form 10-K for the year ended December 31, 1989, filed by Southern California Gas Company. 22 Annual Report on Form 10-K for the year ended December 31, 1990, filed by Southern California Gas Company. 23 Annual Report on Form 10-K for the year ended December 31, 1991, filed by Southern California Gas Company. 24 Registration Statement No. 33-50826 filed by Southern California Gas Company on August 13, 1992. 25 Annual Report on Form 10-K for the year ended December 31, 1992, filed by Southern California Gas Company. 26 Annual Report on Form 10-K for the year ended December 31, 1993, filed by Southern California Gas Company. 27 Registration Statement No. 33-54055 filed by Pacific Enterprises on June 9, 1994. - 52 - 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, thereunto duly authorized. SOUTHERN CALIFORNIA GAS COMPANY By: /s/ Warren I. Mitchell -------------------------- Name: Warren I. Mitchell Title: President Dated: March 17, 1995 - 53 - Each person whose signature appears below hereby authorizes Warren I. Mitchell, Lloyd A. Levitin, Ralph Todaro, and each of them, severally, as attorney-in-fact, to sign on his or her behalf, individually and in each capacity stated below, and file all amendments to this Annual Report. Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated. SIGNATURE TITLE DATE /s/ Warren I. Mitchell - ----------------------- President March 17, 1995 (Warren I. Mitchell) (Principal Executive Officer) /s/ Lloyd A. Levitin - ----------------------- Executive Vice President and (Lloyd A. Levitin) Chief Financial Officer (Principal Financial Officer) March 17, 1995 /s/ Ralph Todaro - ----------------------- Vice President and Controller March 17, 1995 (Ralph Todaro) /s/ Hyla H. Bertea - ----------------------- Director March 17, 1995 (Hyla H. Bertea) /s/ Herbert L. Carter - ----------------------- Director March 17, 1995 (Herbert L. Carter) /s/ Richard D. Farman - ----------------------- Director March 17, 1995 (Richard D. Farman) /s/ Wilford D. Godbold, Jr. - ----------------------- Director March 17, 1995 (Wilford D. Godbold, Jr.) /s/ Ignacio E. Lozano, Jr. - ----------------------- Director March 17, 1995 (Ignacio E. Lozano, Jr.) /s/ Harold M. Messmer, Jr. - ----------------------- Director March 17, 1995 (Harold M. Messmer, Jr.) /s/ Paul A. Miller - ----------------------- Director March 17, 1995 (Paul A. Miller) /s/ Joseph R. Rensch - ----------------------- Director March 17, 1995 (Joseph R. Rensch) /s/ Diana L. Walker - ----------------------- Director March 17, 1995 (Diana L. Walker) /s/ Willis B. Wood, Jr. - ----------------------- Director March 17, 1995 (Willis B. Wood, Jr.) - 54 - EX-3.02 2 EXHIBIT 3.02 Exhibit 3.02 BYLAWS OF SOUTHERN CALIFORNIA GAS COMPANY MARCH 1, 1995 BYLAWS OF SOUTHERN CALIFORNIA GAS COMPANY ____________ ARTICLE I PRINCIPAL OFFICE SECTION 1. The principal executive office of the Company is located at 555 West Fifth Street, City of Los Angeles, County of Los Angeles, California. ARTICLE II MEETINGS OF SHAREHOLDERS SECTION 1. All Meetings of Shareholders shall be held either at the principal executive office of the Company or at any other place within or without the state as may be designated by resolution of the Board of Directors. SECTION 2. An Annual Meeting of Shareholders shall be held each year on such date and at such time as may be designated by resolution of the Board of Directors. SECTION 3. At an Annual Meeting of Shareholders, only such business shall be conducted as shall have been properly brought before the Annual Meeting. To be properly brought before an Annual Meeting, business must be (a) specified in the notice of the Annual Meeting (or any supplement thereto) given by or at the direction of the Board of Directors, (b) otherwise properly brought before the Annual Meeting by a Shareholder. For business to be properly brought before an Annual Meeting by a Shareholder, including the nomination of any person (other than a person nominated by or at the direction of the Board of Directors) for election to the Board of Directors, the Shareholder must have given timely and proper written notice to the Secretary of the Company. To be timely, the Shareholder's written notice must be received at the principal executive office of the Company not less than sixty nor more than one hundred twenty days in advance of the date corresponding to the date of the last Annual Meeting; provided, however, that in the event the Annual Meeting to which the Shareholder's written notice relates is to be held on a date which differs by more than sixty days from the date corresponding to the date of the last Annual Meeting, the Shareholder's written notice to be timely must be so received not later than the close of business on the tenth day following the date on which public disclosure of the date of the Annual Meeting is made or given to Shareholders. To be proper, the Shareholder's written notice must set forth as to each matter the Shareholder proposes to bring before the Annual Meeting (a) a brief description of the business desired to be brought before the Annual Meeting, (b) the name and address of the Shareholder as they appear on the Company's books, (c) the class and number of shares of the Company which are beneficially owned by the Shareholder, and (d) any material interest of the Shareholder in such business. In addition, if the Shareholder's written notice relates to the nomination at the Annual Meeting of any person for election to the Board of Directors, such notice to be proper must also set forth (a) the name, age, business address and residence address of each person to be nominated, (b) the principal occupation or employment of each such person, (c) the number of shares of capital stock beneficially owned by each such person, and (d) such other information concerning each such person as would be required under the rules of the Securities and Exchange Commission in a proxy statement soliciting proxies for the election of such person as a Director, and must be accompanied by a consent, signed by each such person, to serve as a Director of the Company if elected. Notwithstanding anything in the Bylaws to the contrary, no business shall be conducted at an Annual Meeting except in accordance with the procedures set forth in this Section 3. SECTION 4. Each Shareholder of the Company shall be entitled to elect voting confidentiality as provided in this Section 4 on all matters submitted to Shareholders by the Board of Directors and each form of proxy, consent, ballot or other written voting instruction distributed by the Company to Shareholders shall include a check box or other appropriate mechanism by which Shareholders who desire to do so may so elect voting confidentiality. All inspectors of election, vote tabulators and other persons appointed or engaged by or on behalf of the Company to process voting instructions (none of whom shall be a Director or Officer of the Company or any of its affiliates) shall be advised of and instructed to comply with this Section 4 and, except as required or permitted hereby, not at any time to disclose to any person (except to other persons engaged in processing voting instructions), the identity and individual vote of any Shareholder electing voting confidentiality; provided, however, that voting confidentiality shall not apply and the name and individual vote of any shareholder may be disclosed to the Company or to any person (i) to the extent that such disclosure is required by applicable law or is appropriate to assert or defend any claim relating to voting or (ii) with respect to any matter for which votes of Shareholders are solicited in opposition to any of the nominees or the recommendations of the Board of Directors unless the persons engaged in such opposition solicitation provide Shareholders of the Company with voting confidentiality (which, if not otherwise provided, will be requested by the Company) comparable in the opinion of the Company to the voting confidentiality provided by this Section 4. ARTICLE III BOARD OF DIRECTORS SECTION 1. The Board of Directors shall have power to: a. Conduct, manage and control the business of the Company, and make rules consistent with law, the Articles of Incorporation and the Bylaws; b. Elect, and remove at their discretion, Officers of the Company, prescribe their duties, and fix their compensation; c. Authorize the issue of shares of stock of the Company upon lawful terms: (i) in consideration of money paid, labor done, services actually rendered to the Company or for its benefit or in its reorganization, debts or securities cancelled, and tangible or intangible property actually received either by this Company or by a wholly-owned subsidiary; but neither promissory notes of the purchaser (unless adequately secured by collateral other than the shares acquired or unless permitted by Section 408 of the California Corporations Code) nor future services shall constitute payment or part payment for shares of this Company; or (ii) as a share dividend or upon a stock split, reverse stock split, reclassifications of outstanding shares 2 into shares of another class, conversion of outstanding shares into shares of another class, exchange of outstanding shares for shares of another class or other change affecting outstanding shares; d. Borrow money and incur indebtedness for the purposes of the Company, and cause to be executed and delivered, in the Company name, promissory notes, bonds, debentures, deeds of trust, mortgages, pledges, hypothecations or other evidences of debt; e. Elect an Executive Committee and other committees. SECTION 2. The Board of Directors shall consist of not less than nine nor more than seventeen members. The authorized number of Directors shall be fixed from time to time, within the limits specified, by a resolution duly adopted by the Board of Directors. A majority of the authorized number of Directors shall constitute a quorum of the Board. ARTICLE IV MEETING OF DIRECTORS SECTION 1. Meetings of the Board of Directors shall be held at any place which has been designated by resolution of the Board of Directors, or by written consent of all members of the Board. In the absence of such designation, regular meetings shall be held in the principal executive office. SECTION 2. Immediately following each Annual Meeting of Shareholders there shall be a regular meeting of the Board of Directors for the purpose of organization, election of Officers and the transaction of other business. In all months other the month in which the Annual Meeting of Shareholders is held there shall be a regular meeting of the Board of Directors on the first Tuesday of each month at such hour as shall be designated by resolution of the Board of Directors. Notice of regular meetings of the Directors shall be given in the manner described in these Bylaws for giving notice of special meetings. No notice of the regular meeting of Board of Directors which follows the Annual Meeting of Shareholders need be given. SECTION 3. Special meetings of the Board of Directors for any purpose may be called at any time by the President, or by any a majority of the authorized number of Directors. Notice of the time and place of special meetings shall be given to each Director. In case notice is mailed or telegraphed, it shall be deposited in the United States mail or delivered to the telegraph company in the city in which the principal executive office is located at least twenty hours prior to the time of the meeting. In case notice is given personally or by telephone, it shall be delivered at least six hours prior to the time of the meeting. SECTION 4. The transactions of any meeting of the Board of Directors, however called or noticed, shall be as valid as though in a meeting duly held after regular call and notice if a quorum be present and each of the Directors, either before or after the meeting, signs a written waiver of notice, a consent to holding such meeting, or an approval of the minutes thereof or attends the meeting without protesting, prior thereto or at its commencement, the lack of notice to such Director. All such waivers, consents or approvals shall be made a part of the minutes of the meeting. SECTION 5. If any regular meeting of Shareholders or of the Board of Directors falls on a legal holiday, then such meeting shall be held on the next succeeding business day at the same hour. But a special meeting of Shareholders or Directors may be held upon a holiday with the same force and effect as if held upon a business day. 3 ARTICLE V OFFICERS SECTION 1. The Officers of the Company shall be a President, Vice Presidents, one or more of whom, in the discretion of the Board of Directors, may be appointed Executive or Senior Vice President, a Secretary and a Treasurer. The Company may have, at the discretion of the Board of Directors, any other Officers and may also have, at the discretion of and upon appointment by the President, one or more Assistant Secretaries and Assistant Treasurers. One person may hold two or more offices. ARTICLE VI THE PRESIDENT SECTION 1. The President shall be the principal executive officer of the Company, shall have general charge of all of the Company's business and affairs and all of its Officers and shall have all of the powers and perform all of the duties inherent in that office and such additional powers and duties as may be prescribed by the Board of Directors. ARTICLE VII VICE PRESIDENTS SECTION 1. In the President's absence or disability, the Vice Presidents in order of their rank shall perform all of the duties of the President and when so acting shall have all of the powers and be subject to all of the restrictions of the President. The Vice Presidents shall have such other powers and perform such additional duties as may be prescribed by the Board of Directors or the President. ARTICLE VIII SECRETARY SECTION 1. The Secretary shall keep at the principal executive office, a book of minutes of all meetings of Directors and Shareholders, which shall contain a statement of the time and place of the meeting, whether it was regular or special, and if special, how authorized and the notice given, the names of those present at Directors' meetings, the number of shares present or represented by written proxy at Shareholders' meetings and the proceedings. SECTION 2. The Secretary shall give notice of all meetings of Shareholders and the Board of Directors required by the Bylaws or by law to be given, and shall keep the seal of the Company in safe custody. The Secretary shall have such other powers and perform such additional duties as may be prescribed by the Board of Directors or the President. SECTION 3. It shall be the duty of the Assistant Secretaries to help the Secretary in the performance of the Secretary's duties. In the absence or disability of the Secretary, the Secretary's duties may be performed by an Assistant Secretary. 4 ARTICLE IX TREASURER SECTION 1. The Treasurer shall have custody and account for all funds or moneys of the Company which may be deposited with the Treasurer, or in banks, or other places of deposit. The Treasurer shall disburse funds or moneys which have been duly approved for disbursement. The Treasurer shall sign notes, bonds or other evidences of indebtedness for the Company as the Board of Directors may authorize. The Treasurer shall have such other powers and perform such additional duties as may be prescribed by the Board of Directors or the President. SECTION 2. It shall be the duty of the Assistant Treasurers to help the Treasurer in the performance of the Treasurer's duties. In the Treasurer's absence or disability, the Treasurer's duties may be performed by an Assistant Treasurer. ARTICLE X RECORD DATE SECTION 1. The Board of Directors may fix a time in the future as a record date for ascertaining the Shareholders entitled to notice and to vote at any meeting of Shareholders, to give consent to corporate action in writing without a meeting, to receive any dividend, distribution, or allotment of rights or to exercise rights related to any change, conversion, or exchange of shares. The selected record date shall not be more than sixty nor less than 10 days prior to the date of the Meeting nor more than sixty days prior to any other action or event for the purposes for which it is fixed. When a record date is fixed, only Shareholders of Record on that date are entitled to notice and to vote at the Meeting, to give consent to corporate action, to receive a dividend, distribution, or allotment of rights, or to exercise any rights in respect of any other lawful action, notwithstanding any transfer of shares on the books of the Company after the record date. 5 ARTICLE XI INDEMNIFICATION OF AGENTS OF THE COMPANY; PURCHASE OF LIABILITY INSURANCE SECTION 1. For the purposes of this Article, "agent" means any person who is or was a Director, Officer, employee or other agent of the Company, or is or was serving at the request of the Company as a director, officer, employee or agent of another foreign or domestic corporation, partnership, joint venture, trust or other enterprise, or was a director, officer, employee or agent of a foreign or domestic corporation which was a predecessor corporation of the Company or of another enterprise at the request of such predecessor corporation; "proceeding" means any threatened, pending or completed action or proceeding, whether civil, criminal, administrative, or investigative; and "expenses" includes, without limitation, attorneys' fees and any expenses of establishing a right to indemnification under Section 4 or paragraph (d) of Section 5 of this Article. SECTION 2. The Company shall indemnify any person who was or is a party, or is threatened to be made a party, to any proceeding (other than an action by or in the right of the Company to procure a judgment in its favor) by reason of the fact that such person is or was an agent of the Company, against expenses, judgments, fines, settlements and other amounts actually and reasonably incurred in connection with such proceeding if such person acted in good faith and in a manner such person reasonably believed to be in the best interests of the Company, and, in the case of a criminal proceeding, had no reasonable cause to believe the conduct of such person was unlawful. The termination of any proceeding by judgment, order, settlement, conviction or upon a plea of nolo contendere or its equivalent shall not, of itself, create a presumption that the person did not act in good faith and in a manner which the person reasonably believed to be in the best interests of the Company or that the person had reasonable cause to believe that the person's conduct was unlawful. SECTION 3. The Company shall indemnify any person who was or is a party or is threatened to be made a party to any threatened, pending or completed action by or in the right of the Company to procure a judgment in its favor by reason of the fact that such person is or was an agent of the Company, against expenses actually and reasonably incurred by such person in connection with the defense or settlement of such action if such person acted in good faith and in a manner such person believed to be in the best interests of the Company and its Shareholders. No indemnification shall be made under this Section 3 for any of the following: a. In respect of any claim, issue or matter as to which such person shall have been adjudged to be liable to the Company in the performance of such person's duty to the Company and its Shareholders, unless and only to the extent that the court in which such proceeding is or was pending shall determine upon application that, in view of all the circumstances of the case, such person is fairly and reasonably entitled to indemnity for expenses and then only to the extent that the court shall determine; b. Of amounts paid in settling or otherwise disposing of a pending action without court approval; c. Of expenses incurred in defending a pending action which is settled or otherwise disposed of without court approval. SECTION 4. To the extent that an agent of the Company has been successful on the merits in defense of any proceeding referred to in Section 2 or 3 or in defense of any claim, issue or matter therein, the agent shall be indemnified against expenses actually and reasonably incurred by the agent in connection therewith. SECTION 5. Except as provided in Section 4, any indemnification under this Article shall be made by the Company only if authorized in the specific case, upon a determination that indemnification of the agent is proper in the circumstances because the agent has met the applicable standard of conduct set forth in Section 2 or 3, by any of the following: 6 a. A majority vote of a quorum consisting of Directors who are not parties to such proceeding; b. If such a quorum of Directors is not obtainable, by independent legal counsel in a written opinion; c. Approval of the Shareholders, with the shares owned by the person to be indemnified not being entitled to vote thereon; d. The court in which such proceeding is or was pending upon application made by the Company or the agent or the attorney or other person rendering services in connection with the defense, whether or not such application by the agent, attorney or other person is opposed by the Company. SECTION 6. Expenses incurred in defending any proceeding may be advanced by the Company prior to the final disposition of such proceeding upon receipt of an undertaking by or on behalf of the agent to repay such amount if it shall be determined ultimately that the agent is not entitled to be indemnified as authorized in this Article. SECTION 7. The indemnification provided by this Article shall not be deemed exclusive of any other rights to which those seeking indemnification may be entitled under any agreement, vote of Shareholders or disinterested Directors or otherwise, to the extent such additional rights to indemnification are authorized in the Articles of Incorporation of the Company. The rights to indemnity under this Article shall continue as to a person who has ceased to be a Director, Officer, employee, or agent and shall inure to the benefit of the heirs, executors and administrators of the person. SECTION 8. No indemnification or advance shall be made under this Article, except as provided in Section 4 or paragraph (d) of Section 5, in any circumstance where it appears: a. That it would be inconsistent with a provision of the Articles of Incorporation, these Bylaws, a resolution of the Shareholders or an agreement in effect at the time of the accrual of the alleged cause of action asserted in the proceeding in which the expenses were incurred or other amounts were paid, which prohibits or otherwise limits indemnification; b. That it would be inconsistent with any condition expressly imposed by a court in approving a settlement. SECTION 9. The Company shall have the power to purchase and maintain insurance on behalf of any agent of the Company against any liability asserted against or incurred by the agent in such capacity or arising out of the agent's status as such whether or not the Company would have the power to indemnify the agent against such liability under the provisions of this Article. SECTION 10. This Article does not apply to any proceeding against any trustee, investment manager or other fiduciary of an employee benefit plan in such person's capacity as such, even though such person may also be an agent of the Company as defined in Section 1. Nothing contained in this Article shall limit any right to indemnification to which such a trustee, investment manager or other fiduciary may be entitled by contract or otherwise, which shall be enforceable to the extent permitted by applicable law. 7 EX-21.01 3 EXHIBIT 21.01 Exhibit 21.01 Subsidiaries of Southern California Gas Company EcoTrans Aftermarket Corporation EcoTrans OEM Corporation Southern California Gas Tower EX-23.01 4 EXHIBIT 23.01 Exhibit 23.01 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement Nos. 33-51322, 33-53258, 33-59404 and 33-52663 of Southern California Gas Company on Forms S-3 of our report dated January 31, 1995, appearing in this Annual Report on Form 10-K of Southern California Gas Company for the year ended December 31, 1994. DELOITTE & TOUCHE LLP Los Angeles, California March 17, 1995 EX-27.01 5 FINANCIAL DATA SCHEDULE
UT The schedule contains summary financial information extracted from the Consolidated Statement of Income, Balance Sheet and Cash Flows and is qualified in its entirety in reference to such financial statements. 0000092108 SOUTHERN CALIFORNIA GAS COMPANY 1,000 YEAR DEC-31-1994 JAN-01-1994 DEC-31-1994 PER-BOOK 3,212,412 0 1,065,376 497,975 0 4,775,763 834,889 0 643,040 1,477,929 0 196,551 1,396,931 278,201 0 0 86,000 0 0 0 1,340,151 4,775,763 2,586,524 145,603 2,162,294 2,307,897 278,627 16,971 0 105,085 190,513 10,468 180,045 0 0 150,127 0 0
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