ITEM 1. BUSINESS
Southern California Gas Company ("The Gas Company" or the "Company") is a public utility owning and operating a natural gas distribution, transmission and storage system that supplies natural gas in 535 cities and communities throughout a 23,000-square mile service territory with a population of approximately 17.4 million, comprising most of southern California and part 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 residential, commercial, industrial, utility electric generation and wholesale customers through approximately 4.8 million meters in its service area. The Company's markets are separated into core and noncore customers. Core customers consist of approximately 4.8 million meters (4.6 million residential and 200,000 small commercial and industrial). The noncore market consists of approximately 1,600 customers which include utility electric generation, wholesale and large commercial and industrial customers. Most noncore customers procure their own gas rather than purchase gas through the Company.
The Company is subject to regulation by the California Public Utilities Commission ("CPUC") which, among other things, establishes the rates the Company may charge for gas service, including an authorized rate of return on investment. Under current ratemaking policies, the Company's future earnings and cash flow will be determined primarily by the authorized rate of return on rate base, changes to authorized rate base, noncore market pricing and the variance in gas volumes delivered to noncore customers versus CPUC-adopted forecast deliveries and the ability of management to control expenses and investment in line with the amounts authorized by the CPUC to be collected in rates. The impact of any future regulatory restructuring (including the performance based regulation proposal (See "Rates and Regulation")), increased competitiveness in the energy industry, price and availability of electric power generated outside the Company's service area, and electric industry restructuring may also affect the Company's future performance.
For 1997, the CPUC has authorized the Company to earn a rate of return of 9.49% on rate base and 11.6% on common equity compared to 9.42% and 11.6%, respectively, in 1996. In 1997, rate base is expected to remain at approximately the same level as 1996. The Company has achieved or exceeded its authorized rate of return on rate base for the last fourteen consecutive years.
The Gas Company was incorporated in California in 1910. Its principal executive offices are located at 555 West Fifth Street, Los Angeles, California 90013 and its telephone number is (213) 244-1200.
OPERATING STATISTICS
The following table sets forth certain operating statistics of the Company from 1992 through 1996.
OPERATING STATISTICS
- ------------------------------ (1) Beginning January 1, 1994, rates included the ratepayer's portion of the Comprehensive Settlement (the amount included in rates for 1996, 1995 and 1994 was $90 million, $84 million and $119 million, respectively).
(2) The number of degree days for any period of time indicates whether the temperature is relatively hot or cold. A degree day is recorded for each degree the average temperature for any day falls below 65 degrees Fahrenheit.
(3) Estimated calendar degree days.
SERVICE AREA
The Gas Company distributes natural gas throughout a 23,000-square mile service territory with a population of approximately 17.4 million people. As indicated by the following map, its service territory includes most of southern California and part 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 Corporation.
UTILITY SERVICES
The Gas Company's customers are separated, for regulatory purposes, into core and noncore customers. Core customers are primarily residential and small commercial and industrial customers, without alternative fuel capability. Noncore customers consist primarily of utility electric generation ("UEG"), wholesale and large commercial and industrial customers. Gas volumes delivered to UEG customers are greatly affected by the price and availability of electric power generated outside of the Company's service area. UEG and other noncore customers are also sensitive to the price relationship between natural gas and alternate fuels, and many are capable of readily switching from one fuel to another, subject to air quality regulations.
The Gas Company offers two basic utility services, sale of gas and transportation of gas through two business units, one focusing on core distribution customers and the other on large volume gas transportation customers. Most 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% of the Company's core market. Although the revenues from transportation throughput are less than for gas sales, The Gas Company generally earns the same margin whether the Company buys the gas and sells it to the customer or transports gas already owned by the customer. (See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations--Operating Results.")
The Gas Company continues to be obligated to purchase reliable supplies of natural gas to serve the requirements of its core customers. However, the only gas supplies that the Company may offer for sale to noncore customers are the same supplies that it purchases to serve its core customers.
The Gas Company also provides a gas storage service for noncore and off-system customers on a bid and negotiated contract 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. As of December 31, 1996, The Gas Company stored approximately 11 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 UEG requirements. Gas competes with electricity for residential and commercial cooking, water heating, space heating uses and clothes drying, and with other fuels for large industrial, commercial and UEG uses. Growth in The Gas Company's markets is largely dependent upon the health and expansion of the California economy. The Company added approximately 44,000 new meters in 1996. This represents a growth rate of approximately 1%, which is expected to continue for 1997.
During 1996, approximately 97% of residential energy customers in the Company's service area used natural gas for water heating and 94% for space heating. Approximately 78% of those customers used natural gas for cooking and 72% for clothes drying.
Demand for natural gas by noncore customers such as large volume commercial, industrial and UEG customers is very sensitive to the price of alternative competitive fuels. These customers number only approximately 1,600; however, during 1996, they accounted for approximately 16% of total gas revenues and 64% of total gas volumes delivered. External factors such as weather, electric deregulation, the increased use of hydroelectric power, competing pipeline bypass and general economic conditions can result in significant shifts in this market. 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. (See "Competition" below.) In 1996, demand for gas for UEG use decreased as a result of an abundance of less-expensive hydroelectric power from high levels of precipitation last winter.
A comprehensive restructuring of the California electric industry intended to increase competition is scheduled to become effective on January 1, 1998. Under the restructuring plan, California electric utilities generally will purchase electricity from a common power pool. In addition, electric customers will be able to purchase electricity directly from other suppliers. Consequently, future volumes of natural gas the Company transports for electric utilities (currently, approximately 16% of the Company's annual throughput) may be adversely affected by increased use of electricity generated by producers outside the Company's service area. The electric industry restructuring may also result in a reduction of electric rates to core customers, but it is unlikely to overcome the entire cost advantage of natural gas for existing uses.
COMPETITION
Since interstate pipelines began operations in The Gas Company's service area, the Company's throughput to customers in the Kern County area who use natural gas to produce steam for enhanced oil recovery projects has decreased significantly because of the bypass of the Company's system. The decrease in revenues from enhanced oil recovery customers is subject to full balancing account treatment, except for a 5% incentive to the Company, and therefore, does not have a material impact on earnings. Bypass of other Company markets may also occur and the Company is fully at risk for reduction in such noncore volumes due to bypass. However, significant additional bypass would require construction of additional facilities by competing pipelines. The Company is continuing to reduce its costs to maintain competitive rates to transportation customers.
To respond to bypass, the Company has received authorization from the CPUC for expedited review of long-term gas transportation contracts with some noncore customers at lower than tariff rates. The CPUC has also approved changes in the methodology for allocating the Company's costs that eliminate subsidization of core customer rates by noncore customers. This allocation flexibility, together with negotiating authority, has enabled the Company to better compete with new interstate pipelines for noncore customers. In addition, under a capacity brokering 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, a comprehensive settlement of certain regulatory issues (See "Item 7. Management's Discussion and Analysis of Financial Condition and Result of Operations--Company Operations-- Ratemaking Procedures.") has improved the Company's competitiveness by reducing the cost of transportation service to noncore customers.
The Company's operations and those of its customers are affected by a growing number of environmental laws and regulations. These laws and regulations affect current operations as well as future expansion. Increasingly complex administrative and reporting requirements of environmental agencies applicable to commercial and industrial customers utilizing gas are not generally applicable to those using electricity. However, anticipated advancement in natural gas technologies should enable gas equipment to remain competitive with alternate energy sources.
SUPPLIES OF GAS
In 1996, The Gas Company delivered approximately 884 billion cubic feet of natural gas through its system. Approximately 64% of these deliveries were customer-owned gas for which The Gas Company provided transportation services. 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 Company's intrastate transmission system by interstate pipeline companies (primarily El Paso Natural Gas Company and Transwestern Pipeline Company) that provide transportation services for supplies purchased from other sources by The Gas Company or its transportation customers. 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 Gas Company has exercised its step-down option on both the El Paso and Transwestern interstate pipeline systems by 300 million cubic feet per day and 450 million cubic feet per day, respectively, thereby
reducing its firm interstate capacity obligations from 2.25 Bcf per day to 1.45 Bcf per day. The Company's requirements to meet the demand of the core market is approximately 1.05 Bcf per day or 400 MMcf per day below its capacity obligation.
The Company has entered into a FERC approved settlement with Transwestern, and an El Paso settlement is currently pending before the FERC. Both settlements define the amount of the unsubscribed capacity costs that is to be recovered from the Company and the other remaining firm service customers, thus reducing the Company's exposure to higher annual reservation charges. Under existing regulation in California, unsubscribed capacity costs are included in customer rates.
The following table sets forth the sources of gas deliveries by The Gas Company from 1992 through 1996.
SOURCES OF GAS
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* Fixed charges primarily include pipeline demand charges, take or pay settlement costs and other direct billed amounts allocated over the quantities delivered by the interstate pipelines serving the Company.
** The average commodity cost of gas purchased excludes fixed charges.
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 68% of total gas volumes purchased by the Company during 1996, as compared with 62% and 64%, respectively, during 1995 and 1994. These supplies were generally purchased at prices significantly below those for other long-term sources of supply.
The Gas Company estimates that sufficient natural gas supplies will be available to meet the requirements of its customers into the next century.
RATES AND REGULATION
The Gas Company is regulated by the CPUC. The CPUC consists of five commissioners appointed by the Governor of California for staggered six-year terms. It is the responsibility of the CPUC to determine that utilities operate in the best interest of the customer with an opportunity to earn a reasonable return on investment. The regulatory structure is complex and has a very substantial impact on the profitability of the Company.
CURRENT RATEMAKING PROCEDURES
Under current ratemaking procedures, 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, changes to authorized rate base, noncore market pricing, the variance in gas volumes delivered to noncore customers from CPUC-adopted forecast deliveries and by the Company's ability to control expenses and investment in line with the amounts authorized by the CPUC to be collected in rates. (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 1997, approximately 89% of the CPUC-authorized gas margin has been allocated to core customers and 11% to noncore customers, including wholesale customers. Under the current regulatory framework, costs may be reallocated between the core and the noncore customer classes once every other year in a biennial cost allocation proceeding ("BCAP"). The BCAP substantially eliminates the effect on core income of variances in core market demand and gas costs subject to the limitations of the "Gas Cost Incentive Mechanism" ("GCIM").
GCIM is a pilot program, which compares the Company's cost of gas with the average market price of 30-day firm spot supplies delivered to the Company's service area and permits full recovery of all costs within a tolerance band above the average. The cost of purchases above the tolerance band or savings from purchases below the average market price are shared equally between customers and shareholders. A filing has been made with the CPUC requesting a reward to shareholders under the procurement portion of the GCIM. The reward amount will be recognized in income when a final CPUC decision is issued.
The GCIM pilot program is scheduled to expire at the end of March 1997. The Company is currently in discussions with the CPUC to extend the GCIM program.
PERFORMANCE BASED REGULATION
The Company has filed a "performance based regulation" ("PBR") application with the CPUC to replace the general rate case and certain other traditional regulatory proceedings. PBR, if approved, would allow the Company to be more responsive to consumer interests and compete more effectively in contestable markets. Key elements of this proposal include a permanent reduction in base rates of $62 million. In late 1996, the Company increased the amount of the proposed rate reduction to $110 million. Other elements of PBR include an indexing mechanism that would limit future rate increases to the inflation rate less a productivity factor and rate refunds to customers if service quality were to
deteriorate. This new approach would maintain cost based rates, but would link financial performance with changes in productivity. Although PBR in the near term could result in increased earnings volatility, the Company would have the opportunity to improve financial performance over the long-term to the extent it is able to reduce expenses, increase gas deliveries and generate profits from new products and services.
Under the PBR proposal, the Company would be at risk for certain changes in interest rates and cost of capital, variances in core volumes not caused by weather and achievement of productivity improvements.
It is expected that PBR will be implemented during the last half of 1997.
ENVIRONMENTAL MATTERS
The Gas Company has identified and reported to California environmental authorities 42 former gas manufacturing sites for which it (together with other utilities as to 21 of the sites) may have remedial obligations under environmental laws. As of December 31, 1996, ten of the sites have been remediated, of which six have received certification from the California Environmental Protection Agency. One site remedy is in process. Preliminary investigations, at a minimum, have been completed on 39 of the gas plant sites, including those sites at which the remediations described above have been completed. In addition, the Company is one of a large number of major corporations that have been identified as a potentially responsible party for environmental remediation of three industrial waste disposal sites and two landfill sites.
In 1994, the CPUC approved a collaborative settlement which provides for rate recovery of 90 percent of environmental investigation and remediation costs without reasonableness review. In addition, The Gas Company has the opportunity to retain a portion of any insurance recovery to offset the 10 percent of costs not recovered in rates.
At December 31, 1996, the Company's estimated remaining liability for investigation and remediation was approximately $77 million, of which 90% is authorized to be recovered through the rate recovery mechanism described above. The estimated liability is subject to future adjustment pending further investigation. (See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation--Factors Influencing Future Performance--Environmental Matters.") Because of current and expected insurance and rate recovery, the Company believes that compliance with environmental laws and regulations will not have a material adverse effect on its results of operations or financial position.
EMPLOYEES
The Company employs approximately 6,917 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. A contract on wages and working conditions is effective through March 31, 1999.
MERGER OF THE PARENT
On October 14, 1996, the Parent and Enova Corporation ("Enova"), the parent of San Diego Gas & Electric Company, announced a strategic merger of equals. The merger was approved by the shareholders of the Parent and Enova on March 11, 1997. The merger is subject to approval by certain governmental and regulatory agencies, including the CPUC, the Securities and Exchange Commission and the Department of Justice. Approval of the merger is expected to occur in late 1997.
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 for Mr. Dagley and Mr. Arriola. From 1985 until joining Pacific Enterprises in August 1995, Mr. Dagley was Senior Vice President and Controller (1985-1993) and Senior Vice President and Chief Financial Officer (1993-1995) of Transco Energy Company. From 1987 until joining the Company in August 1994, Mr. Arriola was a Vice President of Bank of America NT&SA (1992-1994) and a Vice President of Security Pacific National Bank (1987-1992). Executive officers are elected annually and serve at the pleasure of the Board of Directors. There are no family relationships among any of the Company's executive officers.
ITEM 2.
ITEM 2. PROPERTIES
At December 31, 1996, The Gas Company owned approximately 2,835 miles of transmission and storage pipeline, 43,435 miles of distribution pipeline and 43,130 miles of service piping. It also owned 10 transmission compressor stations and 5 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 leases, and currently 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 1996 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
Market prices for the preferred stock were obtained from the Pacific Stock Exchange. In 1996, the Company redeemed all of the Flexible Auction preferred stock.
ITEM 6.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth certain selected financial data of the Company for 1992 through 1996.
SELECTED FINANCIAL DATA
The Gas Company's parent, Pacific Enterprises, owns 96 percent of the voting stock, including all of the issued and outstanding common stock; therefore, per share data have been omitted.
ITEM 7.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS INTRODUCTION
This section includes management's analysis of operating results from 1994 through 1996, and is intended to provide additional information about the Southern California Gas Company's (the Company) capital resources, liquidity and financial performance. This section also focuses on the major factors expected to influence future operating results and discusses future investment and financing plans. Management's Discussion and Analysis should be read in conjunction with the Consolidated Financial Statements.
The Company, a subsidiary of Pacific Enterprises (the Parent), is a Los Angeles-based utility engaged in supplying natural gas throughout most of southern and part of central California. The Company is the nation's largest natural gas distribution utility, serving 4.8 million meters and 535 cities and communities throughout a 23,000 square mile service territory with a population of approximately 17.4 million.
The Company markets are separated into core customers and noncore customers. Core customers consist of approximately 4.8 million customers (4.6 million residential and 200,000 small commercial and industrial customers). The noncore market consists of approximately 1,600 large customers which includes nine utility electric generation, three wholesale, and the remainder are large commercial and industrial
customers. Most noncore customers procure their own gas supply rather than purchase gas through the Company.
In 1995, the Parent completed a realignment into business units which established a more flexible design to allow a more rapid response to competitive forces. There are two business units at the Company, one focusing on core distribution customers and the other on large volume gas transportation customers.
During 1996, the Parent announced an agreement to combine its operations with Enova Corporation, the parent company of San Diego Gas & Electric. This strategic merger of equals will be a tax free transaction accounted for as a pooling of interests. The combination was approved by the shareholders of both companies on March 11, 1997. Completion of the combination remains subject to approval by regulatory and governmental agencies, including the CPUC. (For further discussion see Note 1 of Notes to Consolidated Financial Statements.)
CAPITAL RESOURCES AND LIQUIDITY
The Company's primary sources and uses of cash during the last three years are summarized in the following condensed statement of cash flows:
CASH FLOWS FROM OPERATING ACTIVITIES
The decrease in cash provided from operating activities to $638 million in 1996 from $663 million in 1995 is primarily due to lower noncore revenues and lower amounts received from undercollected regulatory balancing accounts partially offset by favorable settlements as described later.
The increase in cash provided from operating activities to $663 million in 1995 from $150 million in 1994 is primarily due to a payment of $391 million for the settlement of gas contract issues made in 1994 and increased earnings of the Company as described later.
There are a number of factors that impact the Company's cash flow from operations. These include changes in operating expenses and the authorized return on common equity.
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures primarily represent rate base investment at the Company. The table below summarizes capital expenditures by utility plant classification:
Capital expenditures for 1996 are $34 million lower than 1995, primarily due to the completion in early 1996 of a new customer information system which increased the Company's responsiveness to customer needs and reduced operating costs and less capital required for storage due to a completion of repairs from the 1994 Northridge earthquake.
Capital expenditures for 1995 were $14 million lower than 1994, primarily the result of reduced investing requirements for connecting new customers.
Capital expenditures are estimated to be approximately $196 million in 1997 and will be financed primarily by internally generated funds.
CASH FLOWS FROM FINANCING ACTIVITIES
In 1996, $409 million was used for financing activities. This was primarily the result of a preferred stock redemption of $100 million, a $67 million redemption of the Swiss Franc Bonds, repayment of long-term debt, including $79 million of debt related to the comprehensive settlement (See Note 3 of Notes to Consolidated Financial Statements.) and payment of dividends, partially offset by the issuance of Medium Term Notes in the amount of $75 million.
Cash was used in 1995 primarily for the repayment of short- and long-term debt, including $65 million of debt related to the Comprehensive Settlement.
Cash flow provided by financing activities of $102 million in 1994 was due to the issuance of long-term debt for financing a comprehensive settlement of gas supply contracts and other regulatory issues.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents were $14 million, $13 million and $58 million at December 31, 1996, 1995 and 1994, respectively. The Company anticipates that cash required in 1997 for capital expenditures, dividends and debt payments will be provided by cash generated from operating activities and existing cash balances.
In addition to cash from ongoing operations, the Parent and the Company have available certain multi-year credit agreements that provide backing for the Company's commercial paper program. At December 31, 1996, all bank lines of credit were unused. (For further discussion, see Note 7 of Notes to Consolidated Financial Statements.)
COMPANY OPERATIONS
To fully understand the operations and financial results of the Company it is important to understand the ratemaking procedures that the Company is required to follow.
RATEMAKING PROCEDURES
The Company is regulated by the California Public Utilities Commission (CPUC). It is the responsibility of the CPUC to determine that utilities operate in the best interests of the customer with the opportunity to earn a reasonable return on investment. Current ratemaking procedures are summarized below.
In a general rate case, the CPUC establishes a base 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. General rate cases are typically filed every three years. On June 1, 1995 the Company filed a "Performance Based Regulation" (PBR) application with the CPUC which would replace the general rate case and certain other regulatory proceedings. If approved, PBR would be implemented sometime during the last half of 1997. For a further discussion of PBR, see Factors Influencing Future Financial Performance--Performance Based Regulation.
The CPUC annually adjusts rates for years between general rate cases to reflect the changes in rate base and the effects of inflation as adjusted by a productivity improvement factor. No adjustment for inflation was made to rates in 1997, pending the CPUC's ruling on the Company's PBR Application. Current rates will remain in effect until PBR is implemented. Separate proceedings are held annually to review the Company's cost of capital, including return on common equity, interest costs and changes in capital structure.
Biennial cost allocation proceedings (BCAP) adjust rates to reflect variances in the cost of gas and core customer demand from estimates adopted in a general rate case. This mechanism substantially eliminates the effect on income of variances in core market demand and gas costs subject to limitations of the Gas Cost Incentive Mechanism (GCIM) and the Comprehensive Settlement. (For further discussion, see Note 3 of Notes to Consolidated Financial Statements.)
GCIM is a pilot program, which compares the Company's cost of gas with a benchmark, calculated at the average market price of 30-day firm spot supplies delivered to the Company's service area and permits full recovery of all costs within a tolerance band above that average. The costs of purchases above the tolerance band or savings from purchases below the average market price are shared equally between customers and shareholders.
In the first year of the GCIM (April 1995-March 1995), the Company's cost of gas was within the tolerance band. There was no reward or penalty in the first year; therefore, all gas costs were passed on to the customer.
In the second year of the GCIM (April 1995-March 1996), the cost of gas was below the benchmark. A filing has been made with the CPUC requesting a reward to shareholders under the procurement portion of the GCIM. The reward amount will be recognized in income when a final CPUC decision has been issued. The Company is currently undergoing proceedings to extend the GCIM program following the model of the pilot. (For further discussion of GCIM, see Note 3 of Notes to Consolidated Financial Statements.)
In 1997, SoCalGas introduced monthly gas pricing for the core commercial and industrial customers. Monthly gas pricing will allow the Company to match the need for short-term debt financing to purchase gas with the revenue stream that is generated on a monthly basis. Monthly gas pricing benefits the customer because the current market price of gas is passed on to the customer as opposed to the traditional weighted average cost of gas (WACOG) approach which has been utilized in prior years.
1994-1996 FINANCIAL RESULTS
Under current utility ratemaking policies, the return that the Company is authorized to earn is the product of an authorized rate of return on rate base and the amount of rate base. Rate base consists primarily of the net investment in utility plant. Thus, the Company's earnings are affected by changes in the authorized rate of return on rate base, the change in the authorized 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. The Company refunds or collects in the future the amounts by which certain defined costs vary from the amounts authorized by the CPUC in the rate case or other regulatory proceedings. Also, variations in core revenues from estimates adopted by the CPUC in established rates are refunded or collected through a balancing account mechanism. Through balancing account treatment, the Company is allowed to fully recover amounts recorded as core deferred costs or core revenue shortfalls currently or in the future.
Key financial and operating data for the Company are highlighted in the table below.
- 1996 COMPARED TO 1995 The Company's operating revenues increased $143 million in 1996 compared to 1995. The increase is primarily due to an increase in the average unit cost of gas in 1996 compared to 1995. Since this cost is recoverable in rates subject to GCIM, it is also recorded as revenues, and resulted in increased revenues in 1996. (See Note 2 of Notes to Consolidated Financial Statements for a discussion of related accounting policies.)
The increase in revenue was also generated by demand from refinery customers who required 21 billion cubic feet more gas in 1996 than in 1995. The increase in revenue was partially offset by a decrease in utility electric generation (UEG) noncore revenues. The decrease in the UEG revenues is due to a reduction in transportation volumes as a result of an abundance of less expensive hydroelectricity resulting from high levels of precipitation last winter.
The Company's cost of gas distributed increased $186 million in 1996 due primarily to an increase in the average unit cost of gas. The average commodity cost of gas purchased by SoCalGas, excluding fixed charges for 1996 was $1.88 per thousand cubic feet compared to $1.42 per thousand cubic feet in 1995.
The Company's operation and maintenance expenses decreased $35 million in 1996 compared to 1995. The decrease primarily reflects savings resulting from the Company's continued improvements in efficiency and management's close control of expenses and the nonrecurring favorable settlements, totaling $28.0 million. One settlement was from gas producers for damage incurred to customer and company equipment as a result of impure gas supplies, and the other reflects the resolution of certain environmental insurance claims.
Depreciation and amortization expense increased $11 million for the year ended 1996 compared to 1995. The increase is partially due to the completion and installation of the Customer Information System in the second quarter of 1996, which was capitalized at $65 million and has a twenty-year life.
Net income applicable to Common Stock (after preferred dividends) was $193 million in 1996 compared to $203 million in 1995. The decline in the Company's earnings was primarily due to a nonrecurring non-cash charge of $26.6 million resulting from continuing developments in the CPUC's restructuring of the electric utility industry. The charge was needed because the Company anticipates the future throughput to noncore UEG customers will be below the levels projected in 1993 at the time of the Comprehensive Settlement (See Note 4 of Notes to Consolidated Financial Statements.). Consequently, the Company believes it will not realize the remaining revenue enhancements that were applied to offset the costs of the Comprehensive Settlement.
- 1995 COMPARED TO 1994 The decrease in operating revenues of $308 million in 1995 is primarily due to a reduction in the average unit cost of gas and a decrease in noncore transportation volumes. The Company's cost of gas distributed decreased $255 million in 1995 due to lower volumes of gas purchased for customers and a decrease in the average unit cost of gas. The decrease in transportation volumes was primarily in the utility electric generation market. This was due to an abundance of less expensive hydroelectricity resulting from high levels of precipitation during the 1994-95 winter. The average commodity cost of gas purchased by the Company, excluding fixed charges, for 1995 was $1.42 per thousand cubic feet, compared to $1.68 per thousand cubic feet in 1994.
The Company's operation and maintenance expenses decreased $67 million in 1995. The decrease primarily reflects savings from cost reduction efforts in 1995 and nonrecurring expenses in 1994. Operating costs for 1994 included expenses resulting from the January 1994 earthquake and expenses related to a discontinued capital project.
Net income applicable to Common Stock (after preferred dividends) increased to $203 million in 1995 from $180 million in 1994. The increase was primarily due to the increase in the authorized return on equity to 12% from 11% in 1994 and lower operating expenses from cost reduction efforts.
- ACHIEVED AND AUTHORIZED RATE OF RETURN The Company has achieved or exceeded the rate of return on rate base authorized by the CPUC for 14 consecutive years. In 1996, the Company achieved a 10.31% return on rate base compared to a 9.42% authorized return and a 13.59% return on equity compared to a 11.60% authorized return. The improved returns were primarily due to lower operating costs as a result of increased operating efficiencies and the favorable settlements.
In 1995, the Company achieved a 10.84% return on rate base compared to a 9.67% authorized return and a 13.89% return on equity compared to a 12% authorized return. The improved returns were primarily due to lower operating costs as a result of reduced staffing levels and other cost reduction efforts.
The Company plans to continue efforts to control costs in 1997. In 1997, the Company is authorized to earn 9.49% return on rate base and 11.6% on common equity. Rate base is expected to remain about level with 1996 results.
OPERATING RESULTS
The table below summarizes the components of the Company's throughput and rates charged to customers for the past three years. Rates include the customer portion of the Comprehensive Settlement (See Note 3 of Notes to Consolidated Financial Statements.). The amount included in rates for 1996, 1995 and 1994 were $90 million, $84 million and $119 million respectively.
Although the revenues from transportation throughput are less than from 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, decreased in 1996 compared to 1995 and 1994 as a result of lower demands, primarily by utility electric generators. This resulted from an abundance of inexpensive hydroelectricity resulting from high levels of precipitation last winter reducing the gas demands of UEG customers.
The decrease in throughput in 1995 from 1994 levels was also the result of lower demands, primarily by UEG customers. As previously described under ratemaking procedures, the Company is not at risk for variances in volumes delivered to the core market. Variances in volumes delivered to the noncore market directly impact the Company's results of operation.
FACTORS INFLUENCING FUTURE FINANCIAL PERFORMANCE
Because of the ratemaking and regulatory process as well as the changing energy marketplace, there are several factors that will influence future financial performance. These factors are summarized below.
Under current ratemaking policies, Company net income and cash flow will be determined primarily by the allowed rate of return on common equity, changes in authorized rate base, noncore market pricing, the variance in gas volumes delivered to noncore customers from CPUC-adopted forecast deliveries, and the ability of management to control expenses and investment in line with the amounts authorized by the CPUC to be collected in rates.
Future regulatory restructuring (including the PBR proposal from the Company), increased competitiveness in the industry (including the continuing threat of customers bypassing the Company's system and obtaining service directly from interstate pipelines), and electric industry restructuring could also affect the Company's future performance.
The following detailed discussion addresses each of the major factors expected to influence future financial performance:
Allowed Rate of Return. For 1997, the Company is authorized to earn a rate of return on rate base of 9.49% and a rate of return on common equity of 11.6%, compared to 9.42% and 11.6%, respectively, in 1996. The CPUC has also authorized an increase in the common equity component of the Company's capital structure to 48.0% in 1997 from 47.4% in 1996. The 60 basis point increase in the equity component could potentially add $2 million to earnings in 1997. Rate base is expected to remain at approximately the same level in 1997 as in 1996.
Performance Based Regulation. The Company has filed a PBR application with the CPUC to replace the general rate case and certain other traditional regulatory proceedings. PBR, if approved, would allow the Company to be more responsive to consumer interests and compete more effectively in contestable markets. Key elements of this proposal include a permanent reduction in base rates of $62 million. In late 1996, the Company increased the amount of the proposed rate reduction to $110 million. Other elements of PBR include an indexing mechanism that would limit future rate increases to the inflation rate less a productivity factor and rate refunds to customers if service quality were to deteriorate. This new approach would maintain cost based rates but would link financial performance with changes in productivity. Although PBR in the near term could result in increased earnings volatility, the Company would have the opportunity to improve financial performance over the long term to the extent it was able to reduce expenses, increase energy deliveries and generate profits from new products and services.
Under the PBR proposal, the Company would be at risk for certain changes in interest rates and cost of capital, changes in core volumes not caused by weather, and achievement of productivity improvements. The Company believes PBR will permit the continued applicability of Statement of Financial Accounting Standards No. 71 "Accounting for the Effects of Certain Types of Regulation" (SFAS 71) to account for the Company's operations. However, the terms of PBR ultimately authorized by the CPUC may contain elements that could result in the Company not meeting all the criteria for continued application of SFAS 71 (See Note 2 of Notes to Consolidated Financial Statements for further discussion of SFAS 71.). Because PBR has not yet been approved, the Company's rates in effect at the end of 1996 will continue in effect in 1997 until PBR is implemented.
Management Control of Expenses and Investment. Over the past 14 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.
Electric Industry Restructuring. Demand for natural gas by utility electric generation customers is sensitive to the price and availability of electric power generated in other areas and available for purchase by customers.
On December 20, 1995, the CPUC issued a final decision to restructure California electric utility regulation effective January 1, 1998. On September 23, 1996 California Assembly Bill 1890, a comprehensive bill regarding electric restructuring, was signed into law. Implementation of portions of the plan are expected to need federal administrative approval. Future volumes of natural gas the Company transports for electric utilities may be adversely affected by increased use of electricity generated by out-of-state producers. The electric industry restructuring may also result in a reduction of electric rates to core customers, but it is unlikely to overcome the entire cost advantage of natural gas for existing uses.
The Company has adopted Statement of Financial Accounting Standards No. 121 "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" (SFAS 121) and evaluated its impact on the Company's financial statements, including the potential effect of the electric
industry restructuring. Although the Company believes that the volume of gas transported may be adversely impacted by the electric industry restructuring, it is not anticipated that it would result in an impairment of assets as defined in SFAS 121 because the expected discounted future cash flows from the Company's investment in its gas transportation infrastructure is greater that its carrying amount.
Noncore Bypass. The Company's throughput to enhanced oil recovery (EOR) customers in the Kern County area decreased significantly since 1992 because of the bypass of the Company's system by competing interstate pipelines. The decrease in revenues from EOR customers is subject to full balancing account treatment except for a 5% incentive to the Company, and therefore, does not have a material impact on the Company's earnings.
Bypass of other markets may also occur, and the Company is fully at risk for reduction in non-EOR noncore volumes due to bypass. However, significant additional bypass would require construction of additional facilities by competing pipelines. The Company is continuing to reduce its costs to maintain competitive rates to transportation customers.
Noncore Pricing. To respond to bypass, the Company has received authorization from the CPUC for expedited review of long-term gas transportation service contracts with some noncore customers at lower than tariff rates. In addition, the CPUC has approved changes in methodology that have minimized subsidization of core customer rates by noncore customers. This allocation flexibility, together with negotiating authority, has enabled the Company to better compete with interstate pipelines for noncore customers. Cost allocation between the core and noncore customer groups remains an important issue, however, in the Company's cost allocation proceedings.
Noncore Throughput. The Company's earnings from noncore markets may be adversely impacted if gas throughput to its noncore customers varies from estimates adopted by the CPUC in establishing rates. There is a continuing risk that an unfavorable variance in noncore volumes can result from external factors such as weather, electric restructuring, the increased use of hydro-electric power, competing pipeline bypass of the Company's system and a downturn in general economic conditions. In addition, many noncore customers are especially sensitive to the price relationship between natural gas and alternative fuels, as they are capable of readily switching from one fuel to another, subject to air quality regulations. The Company is at risk for the lost revenue.
Through July 31, 1999, any favorable earnings effect of higher revenues resulting from higher throughput to noncore customers has been eliminated as a result of the Comprehensive Settlement described in Note 3 of Notes to Consolidated Financial Statements.
Excess Interstate Pipeline Capacity. The Company has exercised its step-down option on both the El Paso and Transwestern interstate pipeline systems by 300 million cubic feet (MMcf) per day and 450 MMcf per day, respectively, thereby reducing its firm interstate capacity obligation from 2.25 Bcf per day to 1.45 Bcf per day. The Company's requirements to meet demand at the core market is approximately 1.05 Bcf per day or 400 MMcf per day below its capacity obligation. The Company has entered into an approved settlement with Transwestern, and an El Paso settlement is currently pending before the Federal Energy Regulatory Commission (FERC). Both settlements define the amount of the unsubscribed capacity costs that is to be recovered from the remaining firm service customers, thus reducing the Company's exposure to higher annual reservation charges. Under existing regulation in California, unsubscribed capacity costs are included in customer rates.
The Transwestern settlement regarding the excess pipeline capacity was approved by the FERC in 1995. The settlement with Transwestern requires firm customers, including the Company, to subsidize unsubscribed pipeline costs for a five-year period with Transwestern assuming full responsibility after that time.
In 1996, a settlement was reached with El Paso in which customers, including SoCalGas, will pay for a portion of the excess pipeline capacity. The pipeline costs will be recoverable in rates. The customers may also receive credits from El Paso for any unused capacity which is sold to others. The El Paso settlement is for a ten-year period and was approved by a FERC Administrative Law Judge in early 1997. The settlement is now awaiting approval by the FERC. Both agreements help to spread the burden of excess capacity fairly among the pipeline systems and their customers.
The Company believes that the FERC approved settlement with Transwestern and the proposed settlement with El Paso will not have a significant impact on liquidity or on results of operations as a result of the requirement to subsidize unsubscribed pipeline costs. The settlements result in a reduction in the costs that the Company might be required to pay in the future as a result of unsubscribed pipeline capacity. While the inclusion of the unsubscribed pipeline cost in rates may impact the Company's ability to compete in highly contested markets, the Company does not believe its inclusion will have a significant impact on volumes transported.
ENVIRONMENTAL MATTERS. The Company's operations and those of its customers are affected by a growing number of environmental laws and regulations. These laws and regulations affect current operations as well as future expansion. Increasingly complex administrative and reporting requirements of environmental agencies applicable to commercial and industrial customers utilizing natural gas are not generally required by those using electricity. However, anticipated advancement in natural gas technologies should enable gas equipment to remain competitive with alternate energy sources. Environmental laws also require clean up of facilities no longer in use. Because of current and expected rate recovery, the Company believes that compliance with these laws will not have a significant impact on its results of operations or financial position. For further discussion of environmental and regulatory matters, see Note 5 of Notes to Consolidated Financial Statements.
UNION CONTRACT. The Company and its 5,000 union workers created a new partnership by reaching an important agreement on wages, hours and working conditions. To remain in effect through March 31, 1999, the agreement recognizes the reality of a competitive market by providing increased workforce flexibility while giving represented employees significant job security. In addition, the unions representing the Company's employees signed a letter in support of the PE/Enova merger.
CALIFORNIA ECONOMY. Growth in the Company's markets is largely dependent on the health and expansion of the California economy. SoCalGas added approximately 44,000 new meters in 1996. This represents a growth rate of approximately 1%, which is expected to continue for 1997.
OTHER INCOME AND INTEREST EXPENSE
OTHER INCOME AND DEDUCTIONS. Other income, which primarily consists of interest income from short-term investments and interest income on regulatory accounts receivable balances, was $0.5 million, $6 million and $17 million in 1996, 1995 and 1994, respectively. The decrease from 1995 is primarily due to unusually high short-term investments in 1995, as a result of overcollected gas costs that were refunded to customers in the fourth quarter of 1995. This was partially offset by higher interest income on regulatory accounts receivable balances in 1996 compared to 1995. Other--Net expense consists primarily of contributions and amortization of loss on reacquired debt.
INTEREST EXPENSE. Interest expense was $86 million, $91 million and $105 million in 1996, 1995 and 1994, respectively. Interest expense in 1996 was reduced from the 1995 and 1994 levels as a result of the lower long-term debt balance maintained throughout the year, the redemption of $67 million Swiss Franc bonds and refinancing of Company debt at lower interest rates.
INFORMATION REGARDING FORWARD LOOKING STATEMENT
This Annual Report contains forward-looking statements with respect to matters inherently involving numerous risks and uncertainties. These statements are identified by the words "estimates," "expects," "anticipates," "plans," "believes," and similar expressions.
The analyses employed to develop these statements are necessarily based upon various assumptions involving judgments with respect to the future including, among other factors, national, regional, and local economic, competitive and regulatory conditions, legislative developments, technological developments, inflation rates, weather conditions, financial market conditions, future business decisions, and other uncertainties, all of which are difficult to predict, and many of which are beyond the control of the Company. Accordingly, while the Company believes that the assumptions upon which the forward-looking statements are based are reasonable for purposes of making these statements, there can be no assurance that these assumptions will approximate actual experience, or that the expectations set forth in the forward-looking statements derived from these assumptions will be realized.
ITEM 8.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
STATEMENT OF CONSOLIDATED INCOME
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
CONSOLIDATED BALANCE SHEET
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
STATEMENT OF CONSOLIDATED CASH FLOWS
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
STATEMENT OF CONSOLIDATED SHAREHOLDERS' EQUITY
The number of shares of preferred stock and common stock authorized and outstanding at December 31, 1996 and 1995, is set forth in Note 10 of Notes to Consolidated Financial Statements.
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. MERGER AGREEMENT WITH ENOVA CORPORATION
On October 14, 1996, Pacific Enterprises (Parent) and Enova Corporation (Enova), the parent company of San Diego Gas and Electric, announced an agreement, which both Boards of Directors unanimously approved, for the combination of the two companies, tax-free, in a strategic merger of equals to be accounted for as a pooling of interests. The combination was approved by the shareholders of both companies on March 11, 1997. Completion of the combination remains subject to approval by regulatory and governmental agencies.
As a result of the combination, the Parent and Enova will become subsidiaries of a new holding company and their common shareholders will become common shareholders of the new holding company. Pacific Enterprises' common shareholders will receive 1.5038 shares of the new holding company's common stock for each of their shares of the Parent's common stock, and Enova common shareholders will receive one share of the new holding company's common stock for each of their shares of Enova common stock. Preferred stock of Pacific Enterprises, SoCalGas, and San Diego Gas & Electric will remain outstanding.
The new holding company will be incorporated in California and will be exempt from the Public Utility Holding Company Act as an intrastate holding company.
The merger is subject to approval by certain governmental and regulatory agencies including the California Public Utilities Commission, the Securities and Exchange Commission, and the Department of Justice. In addition, approval or a disclaimer of jurisdiction by the Federal Energy Regulatory Commission is required. Required approvals of the merger are expected to occur in late 1997. In the interim, the Parent and Enova have formed a joint venture to provide integrated energy and energy related products and services.
The Parent owns indirect interests in several small electric generation facilities which are "qualifying facilities" under the Public Utility Regulatory Policies Act. Qualifying facility status is not available to any facilities that are more than 50% owned by an electric utility or an electric utility holding company.
Upon the completion of the proposed business combination, the new holding company will become an electric utility holding company. Consequently, in order to avoid the loss of qualifying facility status, the Parent must cause its ownership in these facilities to be not more than 50% prior to the completion of the business combination. The Parent is considering several alternatives to accomplish this result including the sale of all or part of these facilities.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Southern California Gas Company (the Company) is a subsidiary of Pacific Enterprises (Parent). The Parent owns approximately 96% of the Company's voting stock, including all of its issued and outstanding common stock; therefore, per share data have been omitted.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. One subsidiary has a 15% limited partnership interest in a 52-story office building in which the Company occupies approximately one-half of the leasable space. Investments in 50% or less owned joint ventures and partnerships are accounted for by the equity or cost method, as appropriate.
RECLASSIFICATIONS
Certain changes in account classification have been made in the prior years' consolidated financial statements to conform to the 1996 financial statement presentation.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) REGULATION
In conformity with generally accepted accounting principles (GAAP), the Company's accounting policies reflect the financial effects of rate regulation authorized by the California Public Utilities Commission (CPUC). The Company applies the provisions of Statement of Financial Accounting Standards No. 71, "Accounting for the Effects of Certain Types of Regulation." This statement requires cost-based rate regulated entities that meet certain criteria to reflect the authorized recovery of costs due to regulatory decisions in their financial statements. The Company records Regulatory Assets which represent assets which are being recovered through customer rates or are probable of being recovered through customer rates. As of December 31, 1996, the Company had $376 million of regulatory assets which included the following: costs of reacquiring debt--$47 million; Comprehensive Settlement costs (See Note 3)--$101 million; deferred income taxes--$93 million (See Note 4); environmental remediation-- $77 million (See Note 5); and other costs--$58 million. Maintenance of the regulatory accounts and regulatory accounts receivable represents the only difference in the application of GAAP for the Company versus non-regulated entities.
REGULATORY ACCOUNTS RECEIVABLE--NET
Authorized regulatory balancing accounts are maintained to accumulate undercollections and overcollections from the revenue and cost estimates adopted by the CPUC in setting rates. The Company makes periodic filings with the CPUC to adjust future gas rates to account for such variances.
GAS IN STORAGE
Gas in storage inventory is stated at last-in, first-out (LIFO) cost. As a result of a regulatory accounting procedure, the pricing of gas in storage does not have any effect on net income. If the first-in, first-out (FIFO) method of accounting for gas in storage inventory had been used by the Company, inventory would have been higher than reported at December 31, 1996 and 1995 by $43 million and $21 million, respectively. Other inventories are generally stated at the lower of cost, determined on an average cost basis, or market.
UTILITY PLANT
The costs 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. The depreciation methods are consistent with those used by non-regulated entities.
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
AFUDC represents the cost of funds used to finance the construction of utility plant and is added to its cost. Interest expense of $6 million in 1996, $9 million in 1995 and $4 million in 1994 was capitalized.
OTHER
Cash equivalents include short-term investments purchased with maturities of less than 90 days.
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED) contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
3. REGULATORY MATTERS
RESTRUCTURING OF GAS SUPPLY CONTRACTS
In 1993, the Company and its gas supply affiliates restructured long-term gas supply contracts with suppliers of California offshore and Canadian gas. In the past, the Company's cost of these supplies had been substantially in excess of its average delivered cost of gas for all gas supplies.
The restructured contracts substantially reduced the ongoing delivered costs of these gas supplies and provided lump sum payments totaling $391 million to the suppliers. The expiration date for the Canadian gas supply contract was shortened from 2012 to 2003.
COMPREHENSIVE SETTLEMENT OF REGULATORY ISSUES
On July 20, 1994, the CPUC approved a comprehensive settlement (Comprehensive Settlement) of a number of pending regulatory issues including rate recovery of a significant portion of the restructuring costs associated with long-term gas supply contracts discussed above. The Comprehensive Settlement permits the Company to recover in utility rates approximately 80% of the contract restructuring costs of $391 million and accelerated amortization of related pipeline assets of approximately $140 million, together with interest, over a period of approximately five years. In addition to the gas supply issues, the Comprehensive Settlement addresses certain of the following regulatory issues:
- NONCORE CUSTOMER RATES. The Comprehensive Settlement changed the procedures for determining noncore rates to be charged by the Company to its customers for the five-year period commencing August 1, 1994. Rates charged to the customers are established based upon the Company's recorded throughput to these customers for 1991. The Company will bear the full risk of any declines in noncore deliveries from 1991 levels. Any revenue enhancement from deliveries in excess of 1991 levels will be limited by a crediting account mechanism that will require a credit to customers of 87.5% of revenues in excess of certain limits. These annual limits above which the credit is applicable increase from $11 million to $19 million over the five-year period from August 1, 1994 through July 31, 1999. The Company's ability to report as earnings the results from revenues in excess of its authorized levels from noncore customers due to volume increases has been eliminated for the five years beginning August 1, 1994 as a consequence of the Comprehensive Settlement.
- REASONABLENESS REVIEWS. The Comprehensive Settlement includes settlement of all pending reasonableness reviews with respect to the Company's gas purchases from April, 1989 through March, 1992, as well as certain other future reasonableness review issues.
- GAS COST INCENTIVE MECHANISM. In 1994, the CPUC approved a new process for evaluating the Company's gas purchases, substantially replacing the previous process of reasonableness reviews. The Gas Cost Incentive Mechanism (GCIM) is a three-year pilot program which began April 1, 1994. The GCIM essentially compares the Company's cost of gas with a benchmark level, which is the average price of 30-day firm spot supplies delivered to the Company's market area.
The Company can recover costs of gas purchased in excess of the benchmark to the extent they fall within a tolerance band, which extends to 4% above the benchmark. If the Company's cost of gas exceeds the tolerance level, then the excess cost will be shared equally between customers and
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
3. REGULATORY MATTERS (CONTINUED) shareholders. All savings from gas purchased below the benchmark are shared equally between customers and shareholders.
The Company is currently in discussions with the CPUC to determine the amount of gas purchases for the second year of the program which were below the benchmark and to extend GCIM beyond its third year.
- ATTRITION ALLOWANCES. The Comprehensive Settlement authorized the Company an annual allowance for increases in operating and maintenance expenses for 1996 to the extent that the projected annual inflation rate exceeded 3%. In 1995, attrition was calculated on the inflation rate in excess of 2%. The rate base attrition was based upon a three-year rolling average of recorded net utility plant additions. This was a departure from past regulatory practice of allowing recovery in rates of the full effect of inflation on operating and maintenance expenses. The Company intends to continue to attempt to control operating expenses and investment to amounts authorized in rates to offset the effect of this regulatory change. The most recent decision issued by the CPUC in December 1995 authorized the Company to collect $12 million in rates for the 1996 attrition allowance. Under an agreement reached as part of the Performance Based Regulation (PBR) application, no attrition adjustment was authorized for 1997. The attrition allowance mechanism will be superceded by PBR (See "Ratemaking Procedures" discussed above.).
The Company recorded the impact of the Comprehensive Settlement in 1993. In 1996, an additional charge of $26.6 million was recorded for revenue enhancements recorded as part of the Comprehensive Settlement which will not be collected. See detailed explanation in prior section entitled "Noncore Customer Rates."
Regulatory Accounts Receivable and Regulatory Assets include a total of approximately $191 million and $259 million in 1996 and 1995, respectively, for the recovery of costs as provided in the Comprehensive Settlement. The CPUC authorized the borrowing of $425 million primarily to provide for funds needed under the Comprehensive Settlement. As of December 31, 1996, the Company has $186 million in commercial paper remaining outstanding related to the Comprehensive Settlement (See Note 7).
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. INCOME TAXES
A reconciliation of the difference between computed statutory federal income tax expense and actual income tax expense for operations is as follows:
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
4. INCOME TAXES (CONTINUED) 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 Company pays the amount of taxes applicable to itself had it filed a separate return.
The Company generally provides for income taxes on the basis of amounts expected to be paid currently, except for the provision for deferred 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, 1996 and 1995, $93 million and $109 million, respectively, of deferred income taxes have been offset by an equivalent amount in regulatory assets.
5. COMMITMENTS AND CONTINGENT LIABILITIES
ENVIRONMENTAL OBLIGATIONS
The Company has identified and reported to California environmental authorities 42 former manufactured gas plant sites for which it (together with other utilities as to 21 of these sites) may have remedial obligations under environmental laws. As of December 31, 1996, ten of these sites have been remediated, of which six have received certification from the California Environmental Protection Agency. One site remedy is in process. Preliminary investigations, at a minimum, have been completed on 39 of the gas plant sites, including those sites at which the remediations described above have been completed. In addition, the Company has been named as a potentially responsible party for two landfill sites and three industrial waste disposal sites.
In 1994, the CPUC approved a collaborative settlement which provides for rate recovery of 90% of environmental investigation and remediation costs without reasonableness review. In addition, the Company has the opportunity to retain a percentage of any insurance recoveries to offset the 10% of costs not recovered in rates.
At December 31, 1996, the Company's estimated remaining investigation and remediation liability was $77 million, of which it is authorized to recover 90% through the mechanism discussed above. The estimated liability is subject to future adjustment pending further investigation. 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.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. COMMITMENTS AND CONTINGENT LIABILITIES (CONTINUED) Estimated liabilities for environmental remediation are recorded when amounts are probable and estimable. Amounts authorized to be recovered in rates under the mechanism described above are recorded as a regulatory asset. Possible recoveries of environmental remediation liabilities from third parties are not deducted from the liability shown on the balance sheet.
LITIGATION
The Company is a defendant in various lawsuits arising in the normal course of business. The Company believes that the resolution of these pending claims and legal proceedings will not have a material adverse effect on the Company's financial statements.
OBLIGATIONS UNDER FIRM COMMITMENTS
The Company has commitments for firm pipeline capacity under contracts with pipeline companies that expire at various dates through the year 2006. These agreements provide for payments of an annual reservation charge. The Company recovers such fixed charges in rates. Estimated minimum commitments as of December 31, 1996 are as follows: 1997--$214 million, 1998--$209 million, 1999--$174 million, 2000--$176 million, 2001--$176 million, after 2001--$815 million.
OTHER COMMITMENTS AND CONTINGENCIES
At December 31, 1996, commitments for capital expenditures were approximately $30 million.
6. LEASES
The Company has leases on real and personal property expiring at various dates from 1997 to 2011. The rentals payable under these leases are determined on both fixed and percentage bases and most leases contain options to extend which are exercisable by the Company.
Rental expense under operating leases was $45 million, $45 million and $42 million in 1996, 1995 and 1994, respectively. The following is a schedule of future minimum operating lease commitments as of December 31, 1996:
7. COMPENSATING BALANCES AND SHORT-TERM BORROWING ARRANGEMENTS
The Company has a $650 million multi-year credit agreement requiring annual fees of .07%. The interest rate on this line varies and is derived from formulas based on market rates and the Company's credit ratings. The multi-year credit agreement expires in February 2001. At December 31, 1996, the bank line of credit was unused. The bank line of credit provides backing for the Company's commercial paper program.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
7. COMPENSATING BALANCES AND SHORT-TERM BORROWING ARRANGEMENTS (CONTINUED) At December 31, 1996 and 1995, the Company had $358 million and $415 million, respectively, of commercial paper obligations outstanding. A portion of the outstanding commercial paper relates to the restructuring costs associated with certain long-term gas supply contracts under the Comprehensive Settlement (See Note 3). The weighted average annual interest rate of commercial paper obligations outstanding was 5.36% and 5.66% at December 31, 1996 and 1995, respectively.
At December 31, 1996, the Company has classified $96 million of the commercial paper as long-term debt since it is the Company's intent to continue to refinance that portion of the debt on a long-term basis. The Company intends to utilize the $650 million multi-year credit agreement to refinance the debt on a long-term basis if short-term financing is not available.
8. LONG-TERM DEBT
The annual principal payment requirements of long-term debt for the years 1997, 1998, 1999, 2000 and 2001 are $147 million, $147 million, $75 million, $30 million and $96 million, respectively. Substantially all of utility plant serves as collateral for the First Mortgage Bonds.
CURRENCY RATE SWAPS
In February 1986, the Company issued SFr. 100 million of 5 1/8% bonds which will mature on February 6, 1998. The Company has entered into a swap transaction with a major international bank to hedge the currency exposure. Under the agreement with the bank, the bond issue, interest payments, and other ongoing costs were swapped for fixed annual payments. The terms of the swap result in a U.S. dollar liability of $47 million at an interest rate of 9.725%.
In May 1986, the Company issued SFr. 150 million of 7 1/2% Foreign Interest Payment Securities which are renewable at 10-year intervals at reset interest rates. Interest is payable in U.S. dollars. The principal was exchanged into $75 million at an exchange rate of 1.9925, which is also the minimum rate of exchange for determining the amount of principal repayable in Swiss francs.
8. LONG-TERM DEBT (CONTINUED) On April 30, 1996 investors put back $67 million (90%) of the $75 million Foreign Interest Payment Securities outstanding. The next available put date for the outstanding balance is in the year 2006. The interest rate on the remaining balance was reset to 6 3/8%.
9. FINANCIAL INSTRUMENTS
The fair value of a financial instrument is the amount at which the instrument could be exchanged in a current transaction between willing parties, other than in a forced sale or liquidation. The amounts disclosed represent management's best estimates of fair value.
The carrying amounts of financial instruments including cash and cash equivalents, accounts receivable, account payable and short-term debt approximated fair value as of December 31, 1996 and 1995 because of the relatively short maturity of these instruments. The carrying amount of the currency swaps approximates fair value.
The fair value of the Company's long-term debt, 6% preferred, and 7 3/4% 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 instruments is different from the carrying amount.
The following financial instruments have a fair value which is different from the carrying amount as of December 31.
As a result of the GCIM (See Note 3), the Company enters into a certain amount of gas futures contracts in the open market with the intent of reducing gas costs within the GCIM tolerance band. The Company's policy is to use gas futures contracts to mitigate risk and better manage gas costs. The CPUC has approved the use of gas futures for managing risk associated with the GCIM. For the year ended December 31, 1996, gains or losses from gas futures contracts are not material to the Company's financial statements.
10. CAPITAL STOCK
The amount of capital stock outstanding at December 31 is as follows:
- ------------------------
(a) The Company's Articles of Incorporation authorize the following stocks: 100 million shares of Common Stock; 160,000 shares of 6% Preferred Stock; 840,000 shares of 6% Preferred Stock, Series A; 5 million shares of Series Preferred Stock and 5 million shares of Preference Stock.
(b) In 1996, the Company redeemed $50 million of the Flexible Auction Series A, and $50 million of the Flexible Auction Series C preferred stock.
(c) In the event of any liquidation, dissolution or winding up of the Company, the holders of shares of each series of Preferred Stock and of each series of Series Preferred Stock would be entitled to receive the stated value or the liquidation preference for their shares, plus accrued dividends before any amount shall be paid to the holders of Preference Stock or Common Stock. If the amounts payable with respect to the shares of each series of Preferred Stock or Series Preferred Stock are not paid in full, the holders of such shares will share ratably in any such distribution. After payment in full to the holders of each series of Preferred Stock, Series Preferred Stock and Preference Stock of the liquidating distributions to which they are entitled, the remaining assets and funds of the Company would be divided PRO RATA among the holders of the 6% Preferred Stock and the holders of Common Stock.
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 Company, sell and transport gas to the Company under tariffs approved by the Federal Energy Regulatory Commission. During 1996, 1995, and 1994, billings for such gas purchases totaled $186 million, $141 million, and $215 million, respectively. The Company has long-term gas purchase and transportation agreements with the affiliates extending through the year 2003 requiring certain minimum payments which allow the affiliates to recover the construction cost of their facilities. The Company is obligated to make minimum annual payments to cover the affiliates' operation and maintenance expenses, demand charges paid to their suppliers, current taxes other than income taxes, and debt service costs, including interest expense and scheduled retirement of debt. These long-term agreements were restructured in conjunction with the Comprehensive Settlement previously discussed (See Note 3).
12. PENSION, POSTRETIREMENT AND OTHER EMPLOYEE BENEFIT PLANS
PENSION PLAN
The Company has a noncontributory defined benefit pension plan covering substantially all of its employees. Benefits are based on an employee's years of service and compensation during his or her last years of employment. The Company's policy is to fund the plan annually at a level which is fully deductible for federal income tax purposes and as necessary on an actuarial basis to provide assets sufficient to meet the benefits to be paid to plan members.
In conformity with generally accepted accounting principles for a rate regulated enterprise, the Company has recorded regulatory adjustments to reflect, in net income, pension costs calculated under the actuarial method allowed for ratemaking. The cumulative difference between the net periodic pension cost calculated for financial reporting and ratemaking purposes has been included as a deferred charge or credit in the Consolidated Balance Sheet.
Pension expense was as follows:
12. PENSION, POSTRETIREMENT AND OTHER EMPLOYEE BENEFIT PLANS (CONTINUED) A reconciliation of the plan's 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 allow amortization of the unfunded transition obligation of $256 million over 20 years. The CPUC in late 1992 authorized SFAS 106 amounts to be recovered in rates.
As with pensions, the Company has recorded regulatory adjustments to reflect, in net income, postretirement benefit costs calculated under the actuarial method allowed for ratemaking. The cumulative difference between the net periodic postretirement benefit cost calculated for financial reporting and ratemaking purposes has been included as a deferred charge or credit in the Consolidated Balance Sheet.
The Company's postretirement benefit plans currently provide 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 for regulated companies, and as necessary on an actuarial basis to provide assets sufficient to be paid to plan participants.
Separate trusts for each of the plans have been established exclusively for the benefit payments of each plan. Some of the plans' funds are commingled with the pension funds by the trustee for investment purposes but are accounted for separately per plan.
12. PENSION, POSTRETIREMENT AND OTHER EMPLOYEE BENEFIT PLANS (CONTINUED) The net periodic postretirement benefit expense was as follows:
A reconciliation of the plan's funded status to the postretirement liability recognized in the Consolidated Balance Sheet is as follows:
The assumed health care cost trend rate is 7.0% for 1997. The trend rate is expected to decrease from 1997 to 1998 with a 6.5% 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 $9.7 million on the aggregate of the service and interest cost components of net periodic postretirement cost for 1996 and $77.7 million on the accumulated postretirement benefit obligation at December 31, 1996. The estimated income tax rate used in the return on plan assets is zero since the assets are invested in tax exempt funds.
POSTEMPLOYMENT BENEFITS
The Company accrues its obligation to provide benefits to former or inactive employees after employment but before retirement. There was no impact on earnings since these costs are currently
12. PENSION, POSTRETIREMENT AND OTHER EMPLOYEE BENEFIT PLANS (CONTINUED) recovered in rates as paid, and as such, have been reflected as a regulatory asset. At December 31, 1996 and 1995 the liability was $40 million and $45 million, respectively, and represents primarily workers' compensation and disability benefits.
RETIREMENT SAVINGS PLAN
Upon completion of one year of service, all employees of the Company and certain subsidiaries are eligible to participate in the Company's retirement savings plan administered by bank trustees. Employees may contribute from 1% to 14% of their regular earnings. The Company generally contributes an amount of cash or a number of shares of the Company's common stock of equivalent fair market value which, when added to prior forfeitures, will equal 50% of the first 6% of eligible base salary contributed by employees. The employees' contributions, at the direction of the employees, are primarily invested in the Company's common stock, mutual funds or guaranteed investment contracts. In 1994, 1995 and 1996 the Company's contributions were partially funded by the Pacific Enterprises Employee Stock Ownership Plan and Trust. The Company's compensation expense was $7 million in 1996 and 1995, and $8 million in 1994.
STATEMENT OF MANAGEMENT RESPONSIBILITY FOR CONSOLIDATED FINANCIAL STATEMENTS
The consolidated financial statements have been prepared by management. The integrity and objectivity of these financial statements and the other financial information in the Annual Report, including the estimates and judgments on which they are based, are the responsibility of management. The financial statements have been audited by Deloitte & Touche LLP, independent certified public accountants, appointed by the Board of Directors. Their report is shown on page 43. Management has made available to Deloitte & Touche LLP all of the Company's financial records and related data, as well as the minutes of shareholders' and directors' meetings.
Management maintains a system of internal accounting control which it believes is adequate to provide reasonable, but not absolute, assurance that assets are properly safeguarded and accounted for, that transactions are executed in accordance with management's authorization and are properly recorded and reported, and for the prevention and detection of fraudulent financial reporting. Management monitors the system of internal control for compliance through its own review and a strong internal auditing program which also independently assesses the effectiveness of the internal controls. In establishing and maintaining internal controls, the Company must exercise judgment in determining whether the benefits to be derived justify the costs of such controls.
Management acknowledges its responsibility to provide financial information (both audited and unaudited) that is representative of the Company's operations, reliable on a consistent basis, and relevant for a meaningful financial assessment of the Company. Management believes that the control process enables 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 Company's code of corporate conduct, which is publicized throughout the Company. The Company maintains a systematic program to assess compliance with this policy.
The Board of Directors has an Audit Committee composed solely of directors who are not officers or employees. The Committee recommends for approval by the full Board the appointment of the independent auditors. The Committee meets regularly with management, with the Company's internal auditors, and with the independent auditors. The independent auditors and the internal auditors periodically meet alone with the Audit Committee and have free access to the Audit Committee at any time.
Warren I. Mitchell, President
Larry J. Dagley, Senior Vice President and Chief Financial Officer
January 28, 1997
INDEPENDENT AUDITOR'S REPORT
Southern California Gas Company:
We have audited the consolidated financial statements of Southern California Gas Company and subsidiaries (pages 23 to 41) as of December 31, 1996 and 1995, and for each of the three years in the period ended December 31, 1996. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Southern California Gas Company and its subsidiaries as of December 31, 1996 and 1995, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1996 in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP Los Angeles, California January 28, 1997
QUARTERLY FINANCIAL DATA (UNAUDITED)
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 May 6, 1997. 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" and "Executive Compensation" in the Company's Information Statement for its Annual Meeting of Shareholders scheduled to be held on May 6, 1997. 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 May 6, 1997. Such information is incorporated herein by reference.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
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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.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
SOUTHERN CALIFORNIA GAS COMPANY
By: /s/ WARREN I. MITCHELL ----------------------------------------- Name: Warren I. Mitchell Title: President Dated: March 26, 1997
Each person whose signature appears below hereby authorizes Warren I. Mitchell, Larry J. Dagley, Ralph Todaro, and each of them, severally, as attorney-in-fact, to sign on his or her behalf, individually and in each capacity stated below, and file all amendments to this Annual Report.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
SIGNATURE TITLE DATE - ------------------------------ --------------------------- ------------------- /s/ WARREN I. MITCHELL President - ------------------------------ (Principal Executive March 26, 1997 (Warren I. Mitchell) Officer)
Senior Vice President and /s/ LARRY J. DAGLEY Chief Financial Officer - ------------------------------ (Principal Financial March 26, 1997 (Larry J. Dagley) Officer)
/s/ RALPH TODARO Vice President and - ------------------------------ Controller (Principal March 26, 1997 (Ralph Todaro) Accounting Officer)
/s/ HYLA H. BERTEA - ------------------------------ Director March 26, 1997 (Hyla H. Bertea)
/s/ HERBERT L. CARTER - ------------------------------ Director March 26, 1997 (Herbert L. Carter)
/s/ RICHARD D. FARMAN - ------------------------------ Director March 26, 1997 (Richard D. Farman)
/s/ WILFORD D. GODBOLD, JR. - ------------------------------ Director March 26, 1997 (Wilford D. Godbold, Jr.)
/s/ IGNACIO E. LOZANO, JR. - ------------------------------ Director March 26, 1997 (Ignacio E. Lozano, Jr.)
/s/ PAUL A. MILLER - ------------------------------ Director March 26, 1997 (Paul A. Miller)
/s/ RICHARD J. STEGEMEIER - ------------------------------ Director March 26, 1997 (Richard J. Stegemeier)
/s/ DIANA L. WALKER - ------------------------------ Director March 26, 1997 (Diana L. Walker)
/s/ WILLIS B. WOOD, JR. - ------------------------------ Director March 26, 1997 (Willis B. Wood, Jr.)