ITEM 1. BUSINESS
Southern California Gas Company (The Gas Company or the Company) is a public utility owning and operating a natural gas transmission, storage and distribution 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 16 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 1,000 meters. Noncore customers consist of large-volume gas users such as electric utilities, wholesale and large commercial and industrial customers capable of switching from natural gas to alternate fuels or suppliers.
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. The Company's future earnings and cash flow will be determined primarily by the allowed rate of return on common equity, growth in rate base, noncore pricing and the variance in gas volumes delivered to these customers versus CPUC-adopted forecast deliveries, the recovery of gas and contract restructuring costs if the Comprehensive Settlement (see "Recent Developments - Comprehensive Settlement of Regulatory Issues") is not approved and the ability of management to control expenses and investment in line with the amounts authorized by the CPUC to be collected in rates. Also, the Company's ability to earn revenues in excess of its authorized return from noncore customers due to volume increases will be substantially eliminated for the five years of the Comprehensive Settlement referenced above. This is because forecasted deliveries in excess of the 1991 throughput levels used to establish rates were contemplated in estimating the costs of the Comprehensive Settlement, and are reflected in current year liabilities. In addition, the impact of any future regulatory restructuring and increased competitiveness in the industry, including the continuing threat of customers bypassing the Company's system and obtaining service directly from interstate pipelines, can affect the Company's performance.
For 1994, the CPUC has authorized the Company to earn a rate of return on rate base of 9.22 percent and a 11.00 percent rate of return on common equity compared to 9.99 percent and 11.90 percent, respectively, in 1993. Growth in rate base for 1993 was approximately 1.8 percent and rate base is expected to
increase by approximately 4 percent to 5 percent in 1994. The Company has achieved or exceeded its authorized return on rate base for the last eleven consecutive years and its authorized rate of return on equity for the last nine 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.
RECENT DEVELOPMENTS
REGULATORY ACTIVITY
On December 17, 1993, the CPUC issued its decision in the Company's 1994 general rate case which authorized a net $97 million rate reduction. The Company plans to adjust its operations with the intention of operating within the amounts authorized in rates. Approximately $21 million of the rate reduction represents productivity improvements. Other items include non-operational issues, primarily reductions in marketing programs and income tax effects of the rate reduction. The decision also includes the effects of the reduction of the Company's rate of return authorized in its 1994 cost of capital proceeding, which increased the total reduction in rates to $132 million. New rates emanating from the CPUC decision became effective January 1, 1994.
RESTRUCTURING OF GAS SUPPLY CONTRACTS
The Company and its gas supply affiliates have reached agreements with suppliers of California offshore and Canadian gas for a restructuring of long-term gas supply contracts. The cost of these supplies to the Company has been substantially in excess of its average delivered cost of gas. During 1993, these excess costs totaled approximately $125 million.
The new agreements substantially reduce the ongoing delivered costs of these gas supplies and provide lump sum settlement payments of $375 million to the suppliers. The expiration date for the Canadian gas supply contract has been shortened from 2012 to 2003, and the supplier of California offshore gas continues to have an option to purchase related gas treatment and pipeline facilities owned by the Company's gas supply affiliate. The agreement with the suppliers of Canadian gas is subject to certain Canadian regulatory and other approvals.
COMPREHENSIVE SETTLEMENT OF REGULATORY ISSUES
The Gas Company and a number of interested parties, including the Division of Ratepayer Advocates ("DRA") of the CPUC, large noncore customers and ratepayer groups, have filed for CPUC approval a comprehensive settlement (the "Comprehensive Settlement") of a number of pending regulatory issues including partial rate recovery of restructuring costs associated with the gas supply contracts discussed above. The Comprehensive Settlement, if approved by the CPUC, would permit the Company to recover in utility rates approximately 80 percent of the contract restructuring costs of $375 million and accelerated depreciation of related pipeline assets of its gas supply affiliates of approximately $130 million, together with interest, over a period of approximately five years. The Gas Company has filed a financing application with the CPUC primarily for the borrowing of $425 million to provide for funds needed under the Comprehensive Settlement. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Comprehensive Settlement of Regulatory Issues" for a discussion of the regulatory issues, in addition to the gas supply issues, addressed in the Comprehensive Settlement.
OPERATING STATISTICS
The following table sets forth certain operating statistics of the Company from 1989 through 1993.
OPERATING STATISTICS
SERVICE AREA
The Gas Company distributes natural gas throughout a 23,000-square mile service territory with a population of approximately 16 million people. As indicated by the following map, its service territory includes most of Southern California and portions of Central California.
[MAP]
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.
UTILITY SERVICES
The Gas Company's customers are divided, 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 are primarily electric utilities, wholesale and large commercial and industrial customers, with alternative fuel capability.
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 contribution to earnings whether a particular customer purchases gas from the Company or utilizes the Company's system for transportation of gas purchased from others. (See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations-Ratemaking Procedures.")
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. Noncore customers that elect to purchase gas supplies from the Company must for a two-year period agree to take-or-pay for 75 percent of the gas that they contract to purchase.
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 1993, 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 1993, 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 over 72 percent for clothes drying.
Demand for natural gas by large industrial and UEG customers is very sensitive to the price of alternative competitive fuels. These customers number only approximately 1,000; however, during 1993, accounted for approximately 19 percent of total revenues, 65 percent of total gas volumes delivered and 15 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 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.
Since the completion of the Kern River/Mojave Interstate Pipeline (Mojave) 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. Mojave now delivers to customers formerly served by the Company 350 to 400 million cubic feet of gas per day. 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 as a result of plans by Mojave to extend its pipeline north to Sacramento through portions of the Company's service territory. The effect of bypass is to increase the Company's rates to other customers and thus make its natural gas service less competitive with that of competing pipelines and available alternate fuels.
In response to bypass, 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. 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 the subsidization of core customer rates by noncore customers. Effective in June 1993, these new rate changes implemented the CPUC's 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 reflect the cost of serving each customer class and, together with price discounting authority, has enabled the Company to better compete with 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 "Recent Developments - Comprehensive Settlement of Regulatory Issues") will help the Company's competitiveness by reducing the cost of transportation service to noncore customers.
SUPPLIES OF GAS
In 1993, The Gas Company delivered slightly less than 1 trillion cubic feet of natural gas through its system. Approximately 64 percent of these deliveries were customer-owned gas for which The Gas Company provided transportation services, compared to 65 percent in 1992. 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 (primarily El Paso Natural Gas Company and Transwestern Natural Gas Company) that produce or purchase the supplies or 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).
The following table sets forth the sources of gas deliveries by The Gas Company from 1989 through 1993.
SOURCES OF GAS
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 66 percent of total gas volumes purchased by the Company during 1993, as compared with 61 percent and 69 percent, respectively, during 1992 and 1991. These supplies were generally purchased at prices significantly below those for other long-term sources of supply.
See "Item 7. "Management's Discussion and Analysis of Financial Condition and Results of Operations - Comprehensive Settlement of Regulatory Issues" for a discussion of the contemplated gas cost incentive mechanism.
The Gas Company estimates that sufficient natural gas supplies will be available to meet the requirements of its customers into the next century. Because of the many variables upon which estimates of future service are based, however, actual levels of service may vary significantly from estimated levels.
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 a reasonable profit. The regulatory structure is complex and has a very substantial impact on the profitability of the Company.
The return that the Company is authorized to earn is the product of the 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 1994, approximately 87 percent of the CPUC-authorized gas margin has been allocated to core customers and 13 percent to noncore customers, including wholesale customers. Under the current regulatory framework, costs may be reallocated between the core and the noncore markets once every other year in a biennial cost allocation proceeding (BCAP).
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. In addition, the Company is one of a large number of major corporations that have been named by federal authorities as potentially responsible parties for environmental remediation of two other industrial sites and a landfill site. These 45 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.
The CPUC approved approximately $9 million in the Company's base rates for expenditures beginning in 1990 through 1993 associated with investigating these sites. In addition, the CPUC previously has approved a special ratemaking procedure with respect to environmental remediation costs under which, upon approval by the CPUC on a site-by-site basis, these costs are accumulated for recovery in future rates subject to a reasonableness review. However, in a decision issued in late 1992 in connection with its initial reasonableness review of these costs, the CPUC concluded that the Company had failed to demonstrate by clear and convincing evidence, the reasonableness for rate recovery of the applied for remediation costs under the existing ratemaking procedure. The decision concluded that a reasonableness review procedure may not be appropriate for rate recovery of environmental remediation costs. In addition, the CPUC ordered the Company, along with other California energy utilities and the DRA, to work toward the development of an alternate ratemaking procedure including cost sharing between shareholder and ratepayers.
In November 1993, a collaborative settlement agreement between the above parties was submitted to the CPUC for approval that recommends a ratemaking mechanism that would provide recovery of 90 percent of environmental investigation and remediation costs without reasonableness review. In addition, the utilities would have the opportunity to retain a percentage of any insurance recoveries to offset the 10 percent of costs not recovered in rates. On March 10, 1994, an administrative law judge's proposed decision was issued which adopted the sharing mechanism discussed above. A final CPUC decision is expected in mid-1994.
Through the end of 1993, preliminary investigations at 33 sites have been completed by the Company and remediation liabilities are estimated to be $82 million for all 45 sites. The liability estimated for these sites is subject to future
adjustment pending further investigation. (See Note 5 of Notes to Consolidated Financial Statements set forth in Item 8 of this Annual Report.)
EMPLOYEES
The Company employs approximately 9,000 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 6,400 employees expired on June 30, 1993, principally as a consequence of failure to reach agreement with respect to The Gas Company's proposal to permit the use of outside contractors for certain services now being provided by union represented employees, if costs were not lowered to an amount that would be incurred through the use of outside contractors. In August 1993, after reaching an impasse, the Company unilaterally implemented the majority of its proposals and after two failed strike votes and further negotiations, the Union membership voted in February 1994 on a contract with terms consistent with that implemented by the Company. On February 28, 1994, the Union notified the Company that the contract had been ratified by the membership and a contract was signed on March 9, 1994. The collective bargaining agreement with respect to wages and working conditions will extend through March 31, 1996. The medical plan agreement will expire on December 31, 1995.
MANAGEMENT
The executive officers of Southern California Gas Company are as follows:
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 Mr. Sayles. From 1982 until joining the Company in January 1994, Mr. Sayles was Senior Legal Counsel for TRW, Inc. (1982-1990); Commissioner of Corporations (1991-1992) and Secretary of the California Business, Transportation and Housing Agency (1993) for the State of California.
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.
ITEM 2.
ITEM 2. PROPERTIES
At December 31, 1993, The Gas Company owned approximately 3,280 miles of transmission and storage pipeline, 42,250 miles of distribution pipeline and 42,406 miles of service piping. It also owned thirteen transmission compressor stations and six 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.
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted during the fourth quarter of 1993 to a vote of the Company's security holders.
PART II
ITEM 5.
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
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth certain selected financial data of the Company for 1989 through 1993.
SELECTED FINANCIAL DATA
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern California Gas Company is a subsidiary of Pacific Enterprises (Parent). This section includes management's analysis of operating results from 1991 through 1993, and is intended to provide additional information about the Company's financial performance. This section also focuses on many of the factors that influence future operating results and discusses future investment and financing plans. This section should be read in conjunction with the Consolidated Financial Statements.
FINANCIAL AND OPERATING PERFORMANCE. The Gas Company provides natural gas distribution, transmission and storage in a 23,000-square-mile service area in southern California and parts of central California.
The Company's markets are separated into core customers and noncore customers. Core customers include approximately 4.7 million customers (4.5 million residential and 0.2 million smaller commercial and industrial customers). The noncore market consists of over 1,000 customers which primarily includes utility electric
generation, wholesale, and large commercial and industrial customers. The 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.
Key financial and operating data for the Company are highlighted in the table below.
The Company has achieved or exceeded the rate of return on rate base authorized by the California Public Utilities Commission (CPUC) for 11 consecutive years. In 1994, the Company is authorized to earn 9.22 percent on rate base and 11.00 percent on common equity. This compares to authorized returns of 9.99 percent on rate base and 11.90 percent on common equity in 1993. Rate base is expected to increase approximately 4 percent to 5 percent in 1994.
Net income decreased $4 million in 1993 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 continued reductions in the Company's cost of service, including operating and financing costs, and growth in rate base. During 1992, net income decreased $16 million due primarily to the recognition in 1991 of a $15 million gain on the 1987 sale of the Company's former headquarters property. In addition, 1992 results reflect a reduction in the Company's authorized rate of return on common equity and disallowances related to its new headquarters, partially offset by growth in rate base and higher earnings from the noncore market.
The table below summarizes the components of gas revenues.
The table shows the composition of the Company's throughput and gas revenue for the past three years. Although the revenues associated with transportation volumes 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. Throughput, the total gas sales and transportation volumes moved through the Company's system, is affected by weather and general economic conditions. In addition, throughput has declined over the last two years as a result of bypass of The Gas Company's system, primarily by enhanced oil recovery customers. (See Factors Influencing Future Performance.) The average commodity cost of gas purchased by the Company, excluding fixed charges, for 1993 was $2.21 per thousand cubic feet, compared to $2.24 per thousand cubic feet in 1992 and $2.40 per thousand cubic feet in 1991.
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 a reasonable profit. The current ratemaking procedures are summarized below. Some of these procedures would be modified by the Comprehensive Settlement discussed later in this section.
The return that the Company is authorized to earn is the product of the 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, achievement of the authorized rate of return is affected by other regulatory and operating factors.
General rate applications are filed every three years. New rates emanating from the Company's most recent rate case went into effect on January 1, 1994. 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), depreciation, interest, taxes and return on rate base.
In a process referred to as the annual attrition allowance, the CPUC annually adjusts rates for years between general rate cases to cover the effects of inflation and changes in rate base. Separate proceedings are held annually to review The Gas Company's cost of capital, including return on common equity, interest costs and changes in capital structure.
The CPUC separately reviews and issues decisions on the reasonableness of various aspects of the Company's operations. The CPUC has disallowed costs it determined to
be imprudent, and further disallowances are possible in the future.
In the biennial cost allocation proceeding (BCAP), the CPUC specifies for each two-year period the allocation of total margin to be collected from the Company's core and noncore customer classes and the expected volumes of gas each customer class will consume annually. The Company maintains regulatory accounts to accumulate undercollections and overcollections from customers and makes periodic filings with the CPUC to adjust future gas rates to account for variances between forecasted and actual gas costs and deliveries. In August 1993, the Company filed a $134 million rate increase with the CPUC. Included in this BCAP filing is a rate structure designed to further reduce subsidies by nonresidential core customers to residential customers by better aligning residential rates with the cost of providing residential service. The CPUC, in an interim decision, granted the Company a $121 million revenue increase effective January 1, 1994. A final CPUC decision is expected in late 1994.
For the core market, the regulatory procedures provide for recording 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. Conversely, the Company reduces rates for decreased gas acquisition costs or for higher than projected revenues from increases in demand by core customers.
For the noncore market the CPUC has created a risk-and-reward mechanism. Earnings may be enhanced by delivering higher than forecast gas volumes to noncore customers. Conversely, the Company is at risk for unfavorable variances in noncore volumes or pricing. This upside and downside earnings potential in the noncore market was limited by the CPUC's procurement rulemaking decision in August 1991. This decision significantly reduced the Company's gas procurement activities on behalf of noncore customers and adopted new service level options and rate structures. It also included a provision for balancing account treatment for 75 percent of any undercollection or overcollection in the recovery of noncore margin and other costs, as compared to what was designated by the CPUC, to be recovered or returned in rates at a later date. The CPUC's revised noncore rate design generally provides for single, rolled-in, volumetric rates, which include use-or-pay provisions in lieu of rates with demand charges.
The collection of up-front demand charges had provided compensation to The Gas Company for standing ready
to provide a contracted level of service and buffered the potential earnings loss from lower than forecast volumes in the noncore market. Under certain conditions, noncore rates, including demand charges, and terms of service are negotiable.
REGULATORY ACTIVITY. On December 17, 1993, the CPUC issued its decision in the Company's 1994 general rate case which authorized a net $97 million rate reduction. The Company plans to attempt to adjust its operations with the intention of operating within the amounts authorized in rates. Approximately $21 million of the rate reduction represents productivity improvements. Other items include non-operational issues, primarily reductions in marketing programs and income tax effects of the rate reduction. The decision also includes the effects of the reduction of the Company's rate of return authorized in its 1994 cost of capital proceeding, which increased the total reduction in rates to $132 million. New rates emanating from the decision became effective on January 1, 1994.
RESTRUCTURING OF GAS SUPPLY CONTRACTS. The Company and its gas supply affiliates have reached agreements with suppliers of California offshore and Canadian gas for a restructuring of long-term gas supply contracts. The cost of these supplies to the Company has been substantially in excess of the Company's average delivered cost of gas. During 1993, these excess costs totaled approximately $125 million.
The new agreements substantially reduce the ongoing delivered costs of these gas supplies and provide lump sum settlement payments of $375 million to the suppliers. The expiration date for the Canadian gas supply contract has been shortened from 2012 to 2003, and the supplier of California offshore gas continues to have an option to purchase related gas treatment and pipeline facilities owned by the Company's gas supply affiliate. The agreement with the suppliers of Canadian gas is subject to certain Canadian regulatory and other approvals.
COMPREHENSIVE SETTLEMENT OF REGULATORY ISSUES. The Company and a number of interested parties (including the Division of Ratepayer Advocates of the CPUC, large noncore customers and ratepayer groups) have proposed for CPUC approval a comprehensive settlement (Comprehensive Settlement) of a number of pending regulatory issues including partial rate recovery of restructuring costs associated with the gas supply contracts discussed above. The Comprehensive Settlement, if approved by the CPUC, would permit the Company to recover in utility rates approximately 80 percent of the contract restructuring costs of $375 million and accelerated depreciation of related pipeline assets of its gas supply affiliates of approximately $130
million, together with interest, over a period of approximately five years. The Company has filed a financing application with the CPUC primarily for the borrowing of $425 million to provide for funds needed under the Comprehensive Settlement. In addition to the gas supply issues, the Comprehensive Settlement addresses the following other regulatory issues:
NONCORE CUSTOMER RATES. The Comprehensive Settlement also contemplates changes in the CPUC ratemaking procedures for determining rates to be charged by the Company to its customers for the five-year period commencing with the approval of the Comprehensive Settlement by the CPUC. Rates charged to the customers would be established based upon the Company's recorded throughput to these customers for 1991. The existing limited regulatory balancing account treatment for variances in noncore volumes from those estimated in establishing rates would be eliminated subject to a crediting mechanism for noncore revenues in excess of certain limits. Consequently, the Company would 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 to which the Comprehensive Settlement is applicable.
REASONABLENESS REVIEWS. The Comprehensive Settlement contemplates the settlement of all pending CPUC reasonableness reviews with respect to the Company's gas purchases from 1989 through 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. The Comprehensive Settlement contemplates that a gas cost incentive mechanism (GCIM) would be implemented with an initial term of three years. Gas costs in excess of a tolerance band over average market price would be shared equally between ratepayers and the Company. Savings from gas purchased below the average market price would be also shared equally between the ratepayers and the Company. The GCIM would provide a 4 1/2 percent tolerance band in 1994 and a 4 percent tolerance band in 1995 and
1996. The GCIM is intended to replace the current gas procurement reasonableness review process. On March 16, 1994, the CPUC issued its decision approving the GCIM for implementation for a three year trial period beginning April 1, 1994.
ATTRITION ALLOWANCES. The Comprehensive Settlement contemplates that the Company may receive annual allowances for operational attrition for 1995 and 1996 only to the extent that the annual inflation rate for those years exceeds 2 percent or 3 percent, respectively. This is a departure from past regulatory practice of allowing recovery of the full effect of inflation 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 believes the Comprehensive Settlement will be approved by the CPUC; therefore, it has been reflected in the Company's financial statements. Approximately $465 million is included in Regulatory Accounts Receivable and Regulatory Assets for the recovery of costs as provided in the Comprehensive Settlement. Upon giving effect to liabilities previously recognized at the Company and amounts absorbed by its gas supply affiliates, the costs of the Comprehensive Settlement, including the restructuring of gas supply contracts, did not result in any additional charge to The Gas Company's consolidated earnings. In the event the Comprehensive Settlement is not approved by the CPUC, the Company will seek other regulatory approvals for the recovery of these costs.
FACTORS INFLUENCING FUTURE PERFORMANCE. Based on existing 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 pricing and the variance in gas volumes delivered to these customers versus CPUC-adopted forecast deliveries, the recovery of gas and contract restructuring costs if the Comprehensive Settlement is not approved and the ability of management to control expenses and investment in line with the amounts authorized by the CPUC to be collected in rates. Also, the Company's ability to earn revenues in excess of its authorized return from noncore customers due to volume increases will be substantially eliminated for the five years of the Comprehensive Settlement described above. This is because forecasted deliveries in excess of the 1991 throughput levels used to establish rates were contemplated in estimating the costs of the Comprehensive Settlement, and are reflected in current year liabilities. The impact of any future regulatory restructuring and increased competitiveness in the industry, including the continuing threat of customers bypassing the Company's system and obtaining service
directly from interstate pipelines, can also affect the Company's performance.
The Gas Company's earnings for 1994 will be affected by the reduction in the authorized rate of return on common equity, reflecting the overall decline in cost of capital offset by higher rate base than in 1993. For 1994, the Company is authorized to earn a rate of return on rate base of 9.22 percent and an 11.00 percent rate of return on common equity compared to 9.99 percent and 11.90 percent, respectively, in 1993. Rate base is expected to increase by approximately 4 percent to 5 percent in 1994.
Since the completion of the Kern River/Mojave Interstate Pipeline (Mojave) 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. Mojave now delivers to customers formerly served by the Company 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 for attaining certain throughput levels, and therefore, does not have a material impact on the Company's earnings. However, bypass of other markets may also occur as a result of plans by Mojave to extend its pipeline north to Sacramento through portions of the Company's service territory. The effect of bypass is to increase the Company's rates to other customers and thus make its natural gas service less competitive with that of competing pipelines and available alternate fuels.
In response to bypass, 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. In addition, in December 1992, the CPUC approved changes in the methodology for allocating the Company's cost between core and noncore customers to reduce subsidization of core customer rates by noncore customers. Effective in June 1993, these new rate changes implemented the CPUC's 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 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 the Company's competitiveness by reducing the cost of transportation service to noncore customers.
Over the past 11 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. However, it may not be able to accomplish this goal. It also bears the risk of nonrecovery of margin or other costs authorized by the CPUC for the noncore market subject to the Comprehensive Settlement as discussed above. Unanticipated sharp increases in the inflation rate could also reduce earnings and cash flow. This possibility is increased with the limits on attrition allowance in 1995 and 1996 under the proposed Comprehensive Settlement.
The Company's earnings are subject to variability depending on gas throughput for its noncore customers. 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 and the operational capacity and/or competing pipeline bypass of the Company's system. 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 is a risk that an unfavorable variance in the noncore volumes can result.
The Gas Company's operations are affected by a growing number of environmental laws and regulations. These laws and regulations affect current operations as well as future expansion and also require cleanup of facilities no longer in use. Because of expected regulatory treatment, 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 5 of Notes to Consolidated Financial Statements.
The Company employs approximately 9,000 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 6,400 employees expired on June 30, 1993, principally as a consequence of failure to reach agreement with respect to the Company's proposal to permit the use of outside contractors for certain services now being provided by union represented employees, if costs were not lowered to an amount that would be incurred through the use of outside contractors. In August 1993, after reaching an impasse, the Company unilaterally implemented the majority of its proposals and after two failed strike votes and further negotiations, the Union membership voted in February 1994 on a contract with terms consistent with that implemented by the Company. On February 28, 1994, the Union notified the Company that the contract had been ratified by the membership and a contract was signed on March 9, 1994. The collective bargaining agreement with respect to wages and working conditions will
extend through March 31, 1996. The medical plan agreement will expire on December 31, 1995.
On January 17, 1994, the Company's service area was struck by a major earthquake. The result was a temporary disruption to approximately 150,000 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 impact on the Company's financial statements.
CAPITAL EXPENDITURES. Capital expenditures were $318 million, $326 million and $316 million in 1993, 1992 and 1991, respectively. Capital expenditures for utility plant are expected to be $345 million in 1994 and will be financed by internally-generated funds and by issuance of long-term debt.
LIQUIDITY. In 1993, as a result of the Comprehensive Settlement, Accounts Payable-Affiliates includes the liability for lump sum settlement payments of $375 million to restructure long-term gas supply contracts and the liability for accelerated amortization of related pipeline assets of gas supply affiliates of $130 million; and Regulatory Assets include the long-term portion of the accrual of amounts to be recovered in rates. Regulatory Accounts Receivable increased in 1993 and 1992 reflecting higher undercollections under the BCAP balancing account procedures due primarily to throughput falling below CPUC-adopted forecast levels. The 1993 balance also includes the current portion of the accrual for the Comprehensive Settlement and undercollections for the transition costs in connection with the capacity brokering program.
Regulatory interest income for 1993 and 1992 increased and decreased $3 million respectively, primarily due to the interest earned on the related interest-bearing regulatory accounts. Other-net (deductions) for 1993 and 1992 reflect the disallowances related to the new headquarters property. The loss on the in-substance defeasance of debt transactions recorded in 1992 is also reflected in Other-net.
Interest on long-term debt for 1993 decreased $11 million and increased $10 million in 1992 due to the refinancing of debt at lower interest rates and the timing of new and replacement of previously retired debt issues. Other interest charges (credits) in 1993 increased $10 million reflecting higher accruals for regulatory related issues. The $10 million decrease in 1992 reflected lower interest associated with supplier refunds received and reversals of the interest associated with prior income tax exposures.
The Company expects to incur additional borrowings of $425 million to finance the Comprehensive Settlement. Borrowings are expected to include primarily commercial paper and medium-term notes. The Company has no plans to issue additional debt
beyond that required by the Comprehensive Settlement and up to $100 million to finance ongoing operations.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
STATEMENT OF CONSOLIDATED INCOME
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
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CONSOLIDATED BALANCE SHEET
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
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STATEMENT OF CONSOLIDATED CASH FLOWS
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
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STATEMENT OF CONSOLIDATED LONG-TERM DEBT
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SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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STATEMENT OF CONSOLIDATED SHAREHOLDERS' EQUITY
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
The Gas Company is a subsidiary of Pacific Enterprises (Parent) which owns approximately 96 percent of The Gas 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 subsidiary, Southern California Gas Tower, a wholly-owned subsidiary that 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 of less than 20 percent are accounted for using the cost method.
RESTATEMENTS AND RECLASSIFICATION. Certain changes in account classification have been made in the prior years' consolidated financial statements to conform to the 1993 financial statement presentation.
REGULATION. The Gas Company is a public utility and follows accounting policies prescribed or authorized by the California Public Utilities Commission (CPUC).
INVENTORIES. 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 an effect on net income. If the first-in, first-out (FIFO) method of accounting for gas inventory had been used by the Company, inventory would have been higher than reported at December 31, 1993 and 1992 by $58 million and $66 million, respectively. Materials and supplies are stated at average unit cost.
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.
REVENUES. Operating revenues are recognized in the same period in which the related gas is delivered to customers.
OTHER. Cash equivalents include short-term investments purchased with maturities of less than 90 days. Interest of $7 million in 1993, $6 million in 1992 and $5
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million in 1991 was capitalized. Other major accounting policies are included in the following notes.
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2. Gain On Sale Of Headquarters and Relocation
In 1987, The Gas Company completed an agreement under which the headquarters office property of the Company was sold. In late 1990, the CPUC ruled that the entire after-tax gain of approximately $24 million be returned to ratepayers over a period of 11 years and 11 months without interest. The Gas Company was permitted to retain the investment income it has earned on the net proceeds from the sale to date and will continue to be entitled to this income through the refund period. As a result, the Company recorded a net after-tax gain of $15 million in 1991, which reflects the $24 million gain reduced by the liability due to ratepayers discounted to the date of sale. At December 31, 1993, the discounted refund obligation remaining for the unamortized pre-tax gain (net proceeds of $62 million less book value of the property) was $21 million and is included in Accounts Payable -Other and Other Deferred Credits in the Consolidated Balance Sheet.
In late 1991, the Company moved its corporate headquarters to a new location in downtown Los Angeles. The Company leases about one-half of the space in The Gas Company Tower, and is also a limited partner in the ownership of the building. In connection with the Company's move to The Gas Company Tower, the CPUC performed a review of the costs associated with this new leased office space. In July 1992, the CPUC decided that certain lease expenses and approximately $8 million of related capital expenditures should not be recoverable in future gas rates. The CPUC decision also required that the Company compensate ratepayers over the 20-year life of the lease for the estimated sale value of its 15 percent ownership interest in The Gas Company Tower.
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.
A reconciliation of the difference between computed statutory federal income tax expense and actual income tax expense is as follows:
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The components of income tax expense are as follows:
The principal components of net deferred tax liabilities are as follows:
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 Gas Company pays the amount of taxes applicable to the Company had it filed on a separate return basis.
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, 1993 and 1992, $109 million and $105 million, respectively, of deferred income taxes have been offset by an equivalent amount in Regulatory Assets.
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4. Restructuring of Gas Supply Contracts and Comprehensive Settlement of Regulatory Issues
RESTRUCTURING OF GAS SUPPLY CONTRACTS. The Company and its gas supply affiliates have reached agreements with suppliers of California offshore and Canadian gas for a restructuring of long-term gas supply contracts. The cost of these supplies to the Company has been substantially in excess of the Company's average delivered cost of gas. During 1993, these excess costs totaled approximately $125 million.
The agreements substantially reduce the ongoing delivered costs of these gas supplies and provide lump sum settlement payments of $375 million to the suppliers. The expiration date for the Canadian gas supply contract has been shortened from 2012 to 2003, and the supplier of California offshore gas continues to have an option to purchase related gas treatment and pipeline facilities owned by the Company's gas supply affiliate. The agreement with the suppliers of Canadian gas is subject to certain Canadian regulatory and other approvals.
COMPREHENSIVE SETTLEMENT OF REGULATORY ISSUES. The Company and a number of interested parties (including the Division of Ratepayer Advocates (DRA) of the CPUC, large noncore customers and ratepayer groups) have proposed for CPUC approval a comprehensive settlement (Comprehensive Settlement) of a number of pending regulatory issues including partial rate recovery of restructuring costs associated with the gas supply contracts discussed above. The Comprehensive Settlement, if approved by the CPUC, would permit the Company to recover in utility rates approximately 80 percent of the contract restructuring costs of $375 million and accelerated amortization of related pipeline assets of its gas supply affiliates of approximately $130 million, together with interest, over a period of approximately five years. The Company has filed a financing application with the CPUC primarily for the borrowing of $425 million to provide for funds needed under the Comprehensive Settlement. In addition to the gas supply issues, the Comprehensive Settlement addresses the following other regulatory issues:
NONCORE CUSTOMER RATES. The Comprehensive Settlement also contemplates changes in the CPUC ratemaking procedures for determining rates to be charged by the Company to its customers for the five-year period commencing with the approval of the Comprehensive Settlement by the CPUC. Rates charged to the customers would be established based upon the Company's recorded throughput to these customers for 1991. The existing limited regulatory balancing account treatment for variances in noncore volumes from those estimated in establishing rates would be eliminated subject to a crediting mechanism for noncore revenues in excess of certain limits. Consequently, the Company would bear the full risk of any declines
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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 to which the Comprehensive Settlement is applicable.
REASONABLENESS REVIEWS. The Comprehensive Settlement contemplates the settlement of all pending CPUC reasonableness reviews with respect to the Company's gas purchases from 1989 through 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. The Comprehensive Settlement contemplates that a gas cost incentive mechanism (GCIM) would be implemented with an initial term of three years. Gas costs in excess of a tolerance band over average market price would be shared equally between ratepayers and the Company. Savings from gas purchased below the average market price would be also shared equally between the ratepayers and the Company. The GCIM would provide a 4 1/2 percent tolerance band in 1994 and a 4 percent tolerance band in 1995 and 1996. The GCIM is intended to replace the current gas procurement reasonableness review process. On March 16, 1994, the CPUC issued its decision approving the GCIM for implementation for a three year trial period beginning April 1, 1994.
ATTRITION ALLOWANCES. The Comprehensive Settlement contemplates that the Company may receive annual allowances for operational attrition for 1995 and 1996 only to the extent that the annual inflation rate for those years exceeds 2 percent and 3 percent, respectively. This is a departure from past regulatory practice of allowing recovery of the full effect of inflation 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 believes the Comprehensive Settlement will be approved by the CPUC; therefore, it has been reflected in the Company's financial statements. Approximately $465 million is included in Regulatory
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Accounts Receivable and Regulatory Assets for the recovery of costs as provided in the Comprehensive Settlement. Accounts Payable-Affiliates include the liability for lump sum settlement payments of $375 million to restructure long-term gas supply contracts. 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 Gas Company's consolidated earnings. In the event the Comprehensive Settlement is not approved by the CPUC, the Company will seek other regulatory approvals for the recovery of these costs.
5. Commitments and Contingent Liabilities
ENVIRONMENTAL OBLIGATIONS. 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. In addition, the Company is one of a large number of major corporations that have been named by federal authorities as potentially responsible parties for environmental remediation of two other industrial sites and a landfill site. These 45 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 10 years to 20 years.
The CPUC approved approximately $9 million in the Company's base rates for expenditures beginning in 1990 through 1993, associated with investigating these sites. In addition, the CPUC previously has approved a special ratemaking procedure with respect to environmental remediation costs under which, upon approval by the CPUC on a site-by-site basis, these costs are accumulated for recovery in future rates subject to a reasonableness review. However, in a decision issued in late 1992 in connection with its initial reasonableness review of these costs, the CPUC concluded that the Company had failed to demonstrate, by clear and convincing evidence, the reasonableness for rate recovery of the applied for remediation costs under the existing ratemaking procedure. The decision concluded that a reasonableness review procedure may not be appropriate for rate recovery of environmental remediation costs. In addition, the CPUC ordered the Company along with other California energy utilities and the DRA to work toward the development of an alternate ratemaking procedure including cost sharing between shareholder and ratepayers.
In November 1993, a collaborative settlement agreement between the above parties was submitted to the CPUC for approval that recommends a ratemaking mechanism that would provide recovery of 90 percent of environmental investigation and remediation costs without reasonableness
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review. In addition, the utilities would have the opportunity to retain a percentage of any insurance recoveries to offset the 10 percent of costs not recovered in rates. On March 10, 1994, an administrative law judge's proposed decision was issued which adopted the sharing mechanism discussed above. A final CPUC decision is expected in mid-1994.
Through the end of 1993, preliminary investigations at 33 sites have been completed by the Company and investigation and remediation liabilities are estimated to be $82 million for all 45 sites. The liability estimated for these sites 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. 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.
OTHER COMMITMENTS AND CONTINGENCIES. On January 17, 1994, the Company's service area was struck by a major earthquake. The result was a disruption in service to less than 3 percent of its customers at any given time 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 regulatory mechanism, and should have no impact on the Company's financial statements.
At December 31, 1993, the Company had commitments for capital expenditures of approximately $30 million.
6. Leases
The Gas Company has leases on real and personal property expiring at various dates from 1994 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 excercisable by the Company.
Rental expense under operating leases was $39 million, $37 million and $24 million, in 1993, 1992 and 1991, respectively.
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The following is a schedule of future minimum operating lease commitments as of December 31, 1993:
7. Compensating Balances and Short-term Borrowing Arrangements
The Company has $825 million of unsecured revolving lines of credit, of which $325 million is a multi-year credit agreement requiring annual fees of .125 percent and $500 million is a 364 day credit agreement requiring annual fees of .10 percent. At December 31, 1993, 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, 1993 and 1992, The Gas Company had commercial paper obligations of $267 million and $215 million, respectively, with weighted average annual interest rates of 3.25 percent and 3.81 percent, respectively.
8. In-Substance Defeasance of Debt
During 1992, the Company established irrevocable trusts to satisfy future principal and interest payments related to $200 million of its Series S and U First Mortgage Bonds. The first mortgage bonds, accrued interest thereon and related unamortized debt discount were removed from the 1992 Consolidated Balance Sheet in an in-substance defeasance transaction. The loss resulting from these transactions did not have a material impact on earnings.
9. Fair Value of 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 and 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 these financial
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instruments is different from the carrying amount. The fair value of the swap transaction 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 following financial instruments have a fair value which is different from the carrying amount as of December 31.
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10. Capital Stock
The amount of capital stock outstanding is as follows:
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11. 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 Gas Company, sell and transport gas to the Company under tariffs approved by the Federal Energy Regulatory Commission. During 1993, 1992 and 1991, billings for such gas purchases totaled $344 million, $356 million, and $381 million, respectively. The Gas Company has long-term gas purchase and transportation agreements with the affiliates extending through the year 2012 requiring certain minimum payments which allow the affiliates to recover the construction cost of their facilities. The Gas 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 have recently been restructured in conjunction with the Comprehensive Settlement, previously discussed (see Note 4).
12. Pension, Postretirement and Other Employee Benefit Plans
PENSION PLANS. The Gas 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 his or her last years of employment. The Gas 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 Gas Company has recorded regulatory adjustments to reflect, in net income, pension costs calculated under the actuarial method allowed for ratemaking. The cumulative difference between
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the net periodic pension cost calculated for financial reporting and ratemaking purposes has been included as a deferred charge (credit) in the Consolidated Balance Sheet.
Pension expense is as follows:
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A reconciliation of the pension plans' funded status to the pension liability recognized in the Consolidated Balance Sheet is as follows:
POSTRETIREMENT BENEFIT PLANS. 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; therefore, a regulatory asset has been recorded to reflect the portion of the liability which will be recovered in future rates.
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
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necessary on an actuarial basis to provide assets sufficient to be paid to plan participants. The net periodic postretirement benefit cost was as follows:
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 and 1991, the amounts funded totaled $22 million and $16 million, respectively.
A reconciliation of the plan's funded status to the postretirement benefit liability recognized in the Consolidated Balance Sheet is as follows:
The assumed health care cost trend rate is 8 percent for 1994. 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 $8 million on the aggregate of the service and interest cost components of net periodic postretirement cost for 1993 and $61 million on the accumulated postretirement benefit obligation at December 31, 1993. The estimated income tax rate used in the return on plan assets is zero since the plan assets are invested in tax exempt funds.
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OTHER EMPLOYEE BENEFITS PLANS. 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 Gas 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 interest accounts. The Gas Company's contributions, which were invested in the Parent's common stock, were $9 million each in 1993 and 1992 and $8 million in 1991.
In November 1992, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 112, "Employers' Accounting for Postemployment Benefits" (SFAS 112). SFAS 112 requires the accrual of the obligation to provide benefits to former or inactive employees after employment but before retirement. The new standard will be adopted by the Company in 1994 and is not expected to have a material impact on earnings since these costs, primarily disability benefits, are currently recovered in rates as paid.
In 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 1993.
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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, independent auditors, appointed by the Board of Directors. Their report is shown on the following page. Management has made available to Deloitte & Touche 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 periodically with management, with the Company's internal auditors and with the independent auditors. The independent auditors and the internal auditors also meet alone with the Audit Committee and have free access to the Audit Committee at any time.
Richard D. Farman Chief Executive Officer
Ralph Todaro Vice President, Finance and Controller
January 31, 1994
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INDEPENDENT AUDITORS' REPORT
Southern California Gas Company:
We have audited the consolidated financial statements of Southern California Gas Company and its subsidiary (pages 31 to 53) as of December 31, 1993 and 1992, and for each of the three years in the period ended December 31, 1993. Our audits also included the consolidated financial statement schedules listed in the Index at Item 14(a)2. These financial statements and financial statement schedules 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 present fairly, in all material respects, the financial position of Southern California Gas Company and its subsidiary as of December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. Also, in our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE
Los Angeles, California January 31, 1994
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OTHER INFORMATION QUARTERLY FINANCIAL DATA (UNAUDITED)
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ITEM 9.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
PART III
ITEM 10.
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 April 25, 1994. 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.
ITEM 11. EXECUTIVE COMPENSATION
Information required by this Item is set forth under the caption "Election of Directors", "Executive Compensation" and "Employee Benefit Plans" in the Company's Information Statement for its Annual Meeting of Shareholders scheduled to be held on April 25, 1994. Such information is incorporated herein by reference.
ITEM 12.
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 April 25, 1994. Such information is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Not applicable.
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PART IV
ITEM 14.
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 Independent Auditors.
1.02 Statement of Consolidated Income for the years ended December 31, 1993, 1992 and 1991.
1.03 Statement of Consolidated Cash Flows for the years ended December 31, 1993, 1992 and 1991.
1.04 Consolidated Balance Sheet at December 31, 1993 and 1992.
1.05 Statement of Consolidated Long-Term Debt at December 31, 1993 and 1992. 1.06 Statement of Consolidated Shareholders' Equity for the years ended December 31, 1993, 1992 and 1991.
1.07 Notes to Consolidated Financial Statements.
2. SUPPLEMENTAL FINANCIAL STATEMENT SCHEDULES:
2.01 Report of Deloitte & Touche, Independent Auditors (contained in Item 1.01)
2.02 Utility Plant for the years ended December 31, 1993, 1992 and 1991 - Schedule V. . . . . . . . . . . . . . . . . . . . .
2.03 Accumulated Depreciation and Amortization of Utility Plant for the years ended December 31, 1993, 1992 and 1991 - Schedule VI . . . . . . . . . . . . . . . . . . . .
2.04 Short-Term Borrowings, December 31, 1993, 1992 and 1991 - Schedule IX . . . . . . . . . . . .
- 59 - 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).
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).
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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).
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).
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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).
22. SUBSIDIARIES OF THE REGISTRANT
22.01 List of subsidiaries of Southern California Gas Company. . . . . . . . . . . . . . . . . .
24. CONSENTS OF EXPERTS AND COUNSEL 24.01 Consent of Deloitte & Touche, Independent Auditors. . . . . . . . . . . . . . . . . . .
25. POWER OF ATTORNEY
25.01 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).
(b) REPORTS ON FORM 8-K: The following reports on Form 8-K were filed during the last quarter of 1993.
Report Date Item Reported ----------- ------------- Oct. 29, 1993 Item 5 Nov. 3, 1993 Item 5 Dec. 3, 1993 Item 5 Dec. 17, 1993 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.
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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.
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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.
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.
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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: WILLIS B. WOOD --------------------------------------- Name: WILLIS B. WOOD, JR.
Title: Presiding Director
Dated: March 28, 1994
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Each person whose signature appears below hereby authorizes Lloyd A. Levitin, Ralph Todaro and Warren I. Mitchell, 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
WILLIS B. WOOD, JR. Presiding March 28, 1994 - ------------------------------- Director and Director (Willis B. Wood, Jr.) (Principal Executive Officer)
LLOYD A. LEVITIN Executive Vice - March 28, 1994 - ------------------------------ President and Chief (Lloyd A. Levitin) Financial Officer (Principal Financial Officer)
HYLA H. BERTEA Director March 28, 1994 - ------------------------------ (Hyla H. Bertea)
HERBERT L. CARTER Director March 28, 1994 - ------------------------------ (Herbert L. Carter)
JAMES F. DICKASON Director March 28, 1994 - ------------------------------ (James F. Dickason)
RICHARD D. FARMAN Director March 28, 1994 - ------------------------------ (Richard D. Farman)
WILFORD D. GODBOLD, JR. Director March 28, 1994 - ------------------------------ (Wilford D. Godbold, Jr.)
IGNACIO E. LOZANO, JR. Director March 28, 1994 - ------------------------------ (Ignacio E. Lozano, Jr.)
HAROLD M. MESSMER, JR. Director March 28, 1994 - ------------------------------ (Harold M. Messmer, Jr.)
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PAUL A. MILLER Director March 28, 1994 - ------------------------------ (Paul A. Miller)
JOSEPH N. MITCHELL Director March 28, 1994 - ------------------------------ (Joseph N. Mitchell)
JOSEPH R. RENSCH Director March 28, 1994 - ------------------------------ (Joseph R. Rensch)
ROCCO C. SICILIANO Director March 28, 1994 - ------------------------------ (Rocco C. Siciliano)
LEONARD H. STRAUS Director March 28, 1994 - ------------------------------ (Leonard H. Straus)
DIANA L. WALKER Director March 28, 1994 - ------------------------------ (Diana L. Walker)
APPENDIX TO FORM 10-K
DESCRIPTION OF MAP
This is a map of the State of California. The shaded portions of the map, most of southern and parts of central California, indicate the area served by Southern California Gas Company.