ITEM 1. BUSINESS
THE COMPANY
ORGANIZATION
The Company, a wholly owned subsidiary of SCANA, is a South Carolina corporation organized in 1924 and has its principal executive office at 1426 Main Street, Columbia, South Carolina 29201, telephone number (803) 748-3000. The Company had 3,774 full-time, permanent employees as of December 31, 1997 as compared to 3,637 full-time, permanent employees as of December 31, 1996.
SCANA, a South Carolina corporation, was organized in 1984 and is a public utility holding company within the meaning of PUHCA but is presently exempt from registration under such Act. SCANA holds all of the issued and outstanding common stock of the Company. (See Note 1A of Notes to Consolidated Financial Statements.)
INDUSTRY SEGMENTS
The Company is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and in the purchase and sale, primarily at retail, of natural gas in South Carolina. The Company also renders urban bus service in the metropolitan area of Columbia, South Carolina. The Company's business is subject to seasonal fluctuations. Generally, sales of electricity are higher during the summer and winter months because of air-conditioning and heating requirements, and sales of natural gas are greater in the winter months due to its use for heating requirements.
The Company's electric service area extends into 24 counties covering more than 15,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 30 of the 46 counties in South Carolina and covers more than 21,000 square miles. The total population of the counties representing the Company's combined service area is approximately 2.4 million.
The predominant industries in the territories served by the Company include: synthetic fibers; chemicals and allied products; fiberglass and fiberglass products; paper and wood products; metal fabrication; stone, clay and sand mining and processing; and various textile-related products.
Information with respect to industry segments for the years ended December 31, 1997, 1996 and 1995 is contained in Note 11 of Notes to Consolidated Financial Statements and all such information is incorporated herein by reference.
COMPETITION
The electric utility industry has begun a major transition that could lead to expanded market competition and less regulation. Deregulation of electric wholesale and retail markets is creating opportunities to compete for new and existing customers and markets. As a result, profit margins and asset values of some utilities could be adversely affected. Legislative initiatives at the Federal and state levels are being considered and, if enacted, could mandate market deregulation. The pace of deregulation, future prices of electricity, and the regulatory actions which may be taken by the PSC and the FERC in response to the changing environment cannot be predicted. However, the FERC, in issuing Order 888 in April 1996, has accelerated competition among electric utilities by providing for open access to wholesale transmission service. Order 888 requires utilities under FERC jurisdiction that own, control or operate transmission lines to file nondiscriminatory open access tariffs that offer
to others the same transmission service they provide themselves. The FERC has also permitted utilities to seek recovery of wholesale stranded costs from departing customers by direct assignment. Approximately two percent of the Company's electric revenue is under FERC jurisdiction for the purpose of setting rates for wholesale service. Legislation is pending in South Carolina that would deregulate the state's retail electric market and enable customers to choose their supplier of electricity. The Company is not able to predict whether the legislation will be enacted and, if it is, the conditions it will impose on utilities that currently operate in the state and future market participants.
The Company is aggressively pursuing actions to position itself strategically for the transformed environment. To enhance its flexibility and responsiveness to change, the Company operates Strategic Business Units. Maintaining a competitive cost structure is of paramount importance in the utility's strategic plan. SCE&G has undertaken a variety of initiatives, including reductions in operation and maintenance costs, the accelerated recovery of SCE&G's electric regulatory assets and the shift, for retail ratemaking purposes only, of depreciation reserves from transmission and distribution assets to nuclear production assets. SCE&G has also established open access transmission tariffs and is selling bulk power to wholesale customers at market-based rates. Significant new customer and management information systems will be implemented in 1998. Marketing of services to commercial and industrial customers has been increased significantly. SCE&G has obtained long-term power supply contracts with a significant portion of its industrial customers. The Company believes that these actions as well as numerous others that have been and will be taken demonstrate its ability and commitment to succeed in the new operating environment to come.
Regulated public utilities are allowed to record as assets some costs that would be expensed by other enterprises. If deregulation or other changes in the regulatory environment occur, the Company may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets from its balance sheet. Although the potential effects of deregulation cannot be determined at present, discontinuation of the accounting treatment could have a material adverse effect on the Company's results of operations in the period the write-off is recorded. It is expected that cash flows and the financial position of the Company would not be materially affected by the discontinuation of the accounting treatment. The Company reported approximately $236 million and $62 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $118 million and $52 million, respectively, on its balance sheet at December 31, 1997.
The Company's generation assets are exposed to considerable financial risks in a deregulated electric market. If market prices for electric generation do not produce adequate revenue streams and the enabling legislation or regulatory actions do not provide for recovery of the resulting stranded costs, the Company could be required to write down its investment in these assets. The Company cannot predict whether any write-downs will be necessary and, if they are, the extent to which they would adversely affect the Company's results of operations in the period in which they are recorded. As of December 31, 1997, the Company's net investment in fossil/hydroelectric generation and nuclear generation assets was approximately $977.1 million and $659.1 million, respectively.
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
Capital Requirements
The cash requirements of the Company arise primarily from its operational needs and its construction program. The ability of the Company to replace existing plant investments, as well as to expand to meet future demand for electricity and gas, will depend upon its ability to attract the necessary financial capital on reasonable terms. The Company recovers the costs of providing services through rates charged to customers. Rates for regulated services are generally based on historical costs. As customer growth and inflation occur and the Company continues its ongoing construction program it is necessary to seek increases in rates. As a result the Company's future financial position and results of operations will be affected by its ability to obtain adequate and timely rate and other regulatory relief.
On January 9, 1996 the PSC issued an order granting the Company an increase in retail electric rates of 7.34%, which were designed to produce additional revenues, based on a test year, of approximately $67.5 million annually. The increase has been implemented in two phases. The first phase, an increase in revenues of approximately $59.5 million annually or 6.47%, commenced in January 1996. The second phase, an increase in revenues of approximately $8.0 million annually, based on a test year, or .87%, was implemented in January 1997. The PSC authorized a return on common equity of 12.0%. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million to be collected through rates over a ten-year period. Additionally, the PSC approved accelerated recovery of a significant portion of the Company's electric regulatory assets (excluding deferred income tax assets) and the remaining transition obligation for postretirement benefits other than pensions, changing the amortization periods to allow recovery by the end of the year 2000. The Company's request to shift, for ratemaking purposes, approximately $257 million of depreciation reserves from transmission and distribution assets to nuclear production assets was also approved. The Consumer Advocate appealed certain issues in the order to the South Carolina Circuit Court, which affirmed the PSC's decisions, and subsequently to the South Carolina Supreme Court which is expected to hear the case and issue a ruling prior to the end of 1998. While the outcome of this proceeding is uncertain, the Company does not believe that any significant adverse changes in the rate order is likely. The PSC's order does not apply to wholesale electric revenues under the FERC's jurisdiction, which constitute approximately two percent of the Company's electric revenues. The FERC rejected the transfer of depreciation reserves for rates subject to its jurisdiction.
During 1998 the Company is expected to meet its capital requirements principally through internally generated funds (approximately 92%, after payment of dividends), and the issuance and sale of debt securities and additional equity contributions from SCANA. Short-term liquidity is expected to be provided primarily by issuance of commercial paper. The timing and amount of such sales and the type of securities to be sold will depend upon market conditions and other factors.
The Company's revised estimates of its cash requirements for construction and nuclear fuel expenditures, which are subject to continuing review and adjustment, for 1998 and the two-year period 1999-2000 are as follows:
Type of Facilities 1999-2000 1998 (Millions of Dollars) Electric Plant: Generation. . . . . . . . . . . . . . . . $ 93 $ 56 Transmission. . . . . . . . . . . . . . . 31 16 Distribution. . . . . . . . . . . . . . . 126 46 Other . . . . . . . . . . . . . . . . . . 22 13 Nuclear Fuel. . . . . . . . . . . . . . . . 33 23 Gas . . . . . . . . . . . . . . . . . . . . 35 13 Common. . . . . . . . . . . . . . . . . . . 27 29 Other . . . . . . . . . . . . . . . . . . . - 1 Total . . . . . . . . . . . . . . $367 $197 The above estimates exclude AFC.
During 1997 the Company expended approximately $23.1 million as part of a program to extend the operating lives of certain non- nuclear generating facilities. Additional improvements to be made under the program during 1998, included in the table above, are estimated to cost approximately $57.4 million.
In addition to the Company's capital requirements for 1998 described above, approximately $47.7 million will be required for refunding and retiring outstanding securities and obligations. For the years 1999-2002, the Company has an aggregate of $301.8 million of long-term debt maturing (including approximately $69.2 million for sinking fund requirements, of which $68.7 million may be satisfied by deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits) and $2.2 million of purchase or sinking fund requirements for preferred stock.
SCANA and Westvaco Corporation have formed a limited liability company, Cogen South LLC, to build and operate a $170 million cogeneration facility at Westvaco's Kraft Division Paper Mill in North Charleston, South Carolina. The facility will provide industrial process steam for the Westvaco paper mill and shaft horsepower to enable the Company to generate up to 99 megawatts of electricity. Construction financing is being provided to Cogen South LLC by banks. In addition to the cogeneration LLC, Westvaco has entered into a 20-year contract with the Company for all its electricity requirements at the North Charleston mill at the Company's standard industrial rate. Construction of the plant began in September 1996 and it is expected to be operational in the fall of 1998.
Financing Program
On April 24, 1997 the Company sold $100 million of 6.52% cumulative preferred stock, par value $100 per share. Proceeds from the sale were used to reduce short-term indebtedness incurred for the Company's construction program, to refinance senior securities and for general corporate purposes.
On October 28, 1997 SCE&G Trust I (the "Trust"), a Delaware statutory business trust and a subsidiary of the Company, issued $50 million of 7.55% Trust Preferred Securities, Series A. The Trust used the proceeds from the sale to purchase unsecured 7.55% junior subordinated debentures of the Company. The Company will use the funds to redeem certain series of its preferred stock. The financial statements of the Trust will be consolidated with those of the Company.
The Company's First and Refunding Mortgage Bond Indenture, dated April 1, 1945 (Old Mortgage), contains provisions prohibiting the issuance of additional bonds thereunder (Class A Bonds) unless net earnings (as therein defined) for twelve consecutive months out of the fifteen months prior to the month of issuance are at least twice the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 1997 the Bond Ratio was 4.32. The issuance of additional Class A Bonds also is restricted to an additional principal amount equal to (i) 60% of unfunded net property additions (which unfunded net property additions totaled approximately $579 million at December 31, 1997), (ii) retirements of Class A Bonds (which retirement credits totaled $67.5 million at December 31, 1997), and (iii) cash on deposit with the Trustee.
The Company has a bond indenture dated April 1, 1993 (New Mortgage) covering substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are issued under the New Mortgage on the basis of a like principal amount of Class A Bonds issued under the Old Mortgage which have been deposited with the Trustee of the New Mortgage (of which $185 million were available for such purpose at December 31, 1997), until such time as all presently outstanding Class A Bonds are retired. Thereafter, New Bonds will be issuable on the basis of property additions in a principal amount equal to 70% of the original cost of electric and common plant properties (compared to 60% of value for Class A Bonds under the Old Mortgage), cash deposited with the Trustee, and retirement of New Bonds. New Bonds will be issuable under the New Mortgage only if adjusted net earnings (as therein defined) for twelve consecutive months out of the eighteen months immediately preceding the month of issuance are at least twice the annual interest requirements on all outstanding bonds (including Class A Bonds) and New Bonds to be outstanding (New Bond Ratio). For the year ended December 31, 1997 the New Bond Ratio was 5.87.
Without the consent of at least a majority of the total voting power of the Company's preferred stock, the Company may not issue or assume any unsecured indebtedness if, after such issue or assumption, the total principal amount of all such unsecured indebtedness would exceed 10% of the aggregate principal amount of all of the Company's secured indebtedness and capital and surplus; however, no such consent shall be required to enter into agreements for payment of principal, interest and premium for securities issued for pollution control purposes.
Pursuant to Section 204 of the Federal Power Act, the Company must obtain the FERC authority to issue short-term debt. The FERC has authorized the Company to issue up to $250 million of unsecured promissory notes or commercial paper with maturity dates of twelve months or less, but not later than December 31, 1999. Commercial paper outstanding at December 31, 1997 was $13.3 million.
The Company had $315 million authorized and unused lines of credit at December 31, 1997 including a credit agreement for a maximum of $250 million to support the issuance of commercial paper. Commercial paper outstanding at December 31, 1997 and December 31, 1996 was $13.3 million and $66.1 million, respectively. See "Fuel Financing Agreements" for a discussion of Fuel Company credit agreements.
The Company's Restated Articles of Incorporation prohibit issuance of additional shares of preferred stock without consent of the preferred stockholders unless net earnings (as defined therein) for the twelve consecutive months immediately preceding the month of issuance are at least one and one-half times the aggregate of all interest charges and preferred stock dividend requirements (Preferred Stock Ratio). For the year ended December 31, 1997 the Preferred Stock Ratio was 2.69.
The ratios of earnings to fixed charges (SEC Method) were 3.85, 3.80, 3.41, 3.46 and 3.57 for the years ended December 31, 1997, 1996, 1995, 1994 and 1993, respectively.
During 1997 the Company received $12.1 million in equity contributions from SCANA. These contributions represented proceeds from the sale of common stock through SCANA's Investor Plus Plan and Stock Purchase Savings Program which in 1996 raised $4.4 million and $24.5 million, respectively, in equity capital. Effective February 1, 1997 SCANA converted the Investor Plus Plan from an original issue plan to a market purchase plan. The SPSP converted from an original issue plan to a market purchase plan on July 1, 1997.
The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the next twelve months and for the foreseeable future.
Fuel Financing Agreements
The Company has assigned to Fuel Company all of its rights and interests in its various contracts relating to the acquisition and ownership of nuclear and fossil fuels. To finance nuclear and fossil fuels and sulfur dioxide emission allowances, Fuel Company issues, from time to time, commercial paper which is supported, up to $125 million, by an irrevocable revolving credit agreement which expires December 19, 2000. Accordingly, the amounts outstanding have been included in long-term debt. This commercial paper and amounts outstanding under the revolving credit agreement, if any, are guaranteed by the Company. The full amount of the credit agreement was available at December 31, 1997.
At December 31, 1997 commercial paper outstanding was approximately $80.3 million at a weighted average interest rate of 5.87%. (See Notes 1M and 4 of Notes to Consolidated Financial Statements.)
ELECTRIC OPERATIONS
Electric Sales
In 1997 residential sales of electricity accounted for 41% of electric sales revenues; commercial sales 31%; industrial sales 20%; sales for resale 2%; and all other 6%. KWH sales by classification for the years ended December 31, 1997 and 1996 are presented below:
Sales KWH % Classification 1997 1996 Change (thousands)
Residential 5,647,185 5,939,703 (4.92) Commercial 5,321,738 5,222,517 1.90 Industrial 5,434,231 5,320,515 2.14 Sale for resale 485,206 1,023,211 (52.58) Other 505,808 505,793 - Total Territorial 17,394,168 18,011,739 (3.43) Negotiated Market Share Tariff 1,459,097 895,016 63.02 Total 18,853,265 18,906,755 (0.28)
Sales for resale includes electricity furnished for resale to three municipalities and two electric cooperatives. One electric cooperative has notified the Company of its intent to terminate in the year 2000 its wholesale power contract with the Company and bid out its electric requirements. Sales under the Negotiated Market Sales Tariff during 1997 includes sales to 28 investor-owned utilities, three electric cooperatives, two municipalities and three federal/state electric agencies. During 1996, sales under the Negotiated Market Sales Tariff includes sales to thirteen investor-owned utilities, one electric cooperative and two state electric agencies.
The electric sales volume for residential sales decreased for 1997 as a result of milder weather. The decrease in sales for resale and the increase of sales under the Negotiated Market Sales Tariff was a result of a municipality terminating its wholesale power contract and transferring to a Negotiated Market Rate. During 1997 the Company recorded a net increase of 10,583 electric customers, increasing its total customers to 503,929. The all-time peak demand of 3,734 MW was set on August 13, 1997.
Electric Interconnections
The Company purchases all of the electric generation of Williams Station, owned by GENCO, under a Unit Power Sales Agreement which has been approved by the FERC. Williams Station has a generating capacity of 560 MW.
The Company's transmission system is part of the interconnected grid extending over a large part of the southern and eastern portions of the nation. The Company, Virginia Power Company, Duke Power Company, Carolina Power & Light Company, Yadkin, Incorporated and PSA are members of the Virginia-Carolinas Reliability Group, one of the several geographic divisions within the Southeastern Electric Reliability Council. This Council provides for coordinated planning for reliability among bulk power systems in the Southeast. The Company is also interconnected with Georgia Power Company, Savannah Electric & Power Company, Oglethorpe Power Corporation and Southeastern Power Administration's Clark Hill Project.
Fuel Costs
The following table sets forth the average cost of nuclear fuel and coal and the weighted average cost of all fuels (including oil and natural gas) used by the Company and GENCO for the years 1995-1997.
1997 1996 1995 Nuclear: Per million BTU $ .47 $ .47 $ .48 Coal: Company: Per ton $38.22 $39.27 $40.01 Per million BTU 1.54 1.55 1.57 GENCO: Per ton $44.49 $41.66 $42.21 Per million BTU 1.61 1.62 1.63 Weighted Average Cost of All Fuels: Per million BTU $ 1.52 $ 1.52 $ 1.26
The fuel costs for 1995 shown above exclude the effects of a PSC-approved offsetting of fuel costs through the application of credits carried on the Company's books as a result of a 1980 settlement of certain litigation. Fuel Supply
The following table shows the sources and approximate percentages of total for the Company's KWH generation (including Williams Station) by each category of fuel for the years 1995-1997 and the estimates for 1998 and 1999.
Percent of Total KWH Generated Estimated Actual 1999 1998 1997 1996 1995
Coal 73% 69% 63% 71% 65% Nuclear 22 26 31 24 27 Hydro 5 5 6 5 5 Natural Gas & Oil - - - - 3 100% 100% 100% 100% 100%
Coal is used at all five of the Company's major fossil fuel- fired plants and GENCO's Williams Station. Unit train deliveries are used at all of these plants and truck deliveries are used at three of these plants. On December 31, 1997 the Company had approximately a 41-day supply of coal in inventory and GENCO had approximately a 30-day supply.
The supply of coal is obtained through contracts and purchases on the spot market. Spot market purchases are expected to continue for coal requirements in excess of those provided by the Company's existing contracts. Contracts for the purchase of coal represent 96.1% of estimated requirements for 1998 (approximately 5.8 million tons, including requirements of Williams Station).
The supply of contract coal is purchased from nine suppliers located in eastern Kentucky, Tennessee and southwest Virginia. Contract commitments, which expire at various times from 1998-2006, approximate 5.5 million tons annually. Sulfur restrictions on the contract coal range from .75% to 2%.
The Company believes that its operations are in substantial compliance with all existing regulations relating to the discharge of sulfur dioxide. The Company is unaware that any more stringent sulfur content requirements for existing plants are contemplated at the State level by DHEC. However, the Company will be required to meet the more stringent Federal emissions standards established by the Clean Air Act (see "Environmental Matters").
The Company has adequate supplies of uranium or enriched uranium product under contract to manufacture nuclear fuel for Summer Station through 2005. The following table summarizes all contract commitments for the stages of nuclear fuel assemblies: Remaining Expiration Commitment Contractor Regions(1) Date
Enrichment USEC (2) 13-18 2005 Fabrication Westinghouse 13-21 2009
(1) A region represents approximately one-third to one-half of the nuclear core in the reactor at any one time. Region no. 13 was loaded in 1997 and Region no. 14 will be loaded in 1999.
(2) Contract provisions for the delivery of enriched uranium product encompass uranium supply and conversion and enrichment services.
The Company has on-site spent nuclear fuel storage capability until at least 2009 and expects to be able to expand its storage capacity to accommodate the spent fuel output for the life of the plant through rod consolidation, dry cask storage or other technology as it becomes available. In addition, there is sufficient on-site storage capacity over the life of Summer Station to permit storage of the entire reactor core in the event that complete unloading should become desirable or necessary for any reason. (See "Nuclear Fuel Disposal" under "Environmental Matters" for information regarding the contract with the DOE for disposal of spent fuel.)
Decommissioning
Decommissioning of Summer Station is presently scheduled to commence when the operating license expires in the year 2022. Based on a 1991 study, the expenditures (on a before-tax basis) related to the Company's share of decommissioning activities are estimated, in 2022 dollars assuming a 4.5% annual rate of inflation, to be $545.3 million including partial reclamation costs. The Company is providing for its share of estimated decommissioning costs of Summer Station over the life of Summer Station. The Company's method of funding decommissioning costs is referred to as COMReP (Cost of Money Reduction Plan). Under this plan, funds collected through rates ($3.2 million in 1997 and 1996) are used to pay premiums on insurance policies on the lives of certain Company personnel. The Company is the beneficiary of these policies. Through these insurance contracts, the
Company is able to take advantage of income tax benefits and accrue earnings on the fund on a tax-deferred basis at a rate higher than can be achieved using more traditional funding approaches. Amounts for decommissioning collected through electric rates, insurance proceeds, and interest on proceeds less expenses are transferred by the Company to an external trust fund in compliance with the financial assurance requirements of the NRC. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis. The trust's sources of decommissioning funds under the COMReP program include investment components of life insurance policy proceeds, return on investment and the cash transfers from the Company described above. The Company records its liability for decommissioning costs in deferred credits.
GAS OPERATIONS
Gas Sales
In 1997 residential sales accounted for 43% of gas sales revenues; commercial sales 31%; industrial sales 26%. Dekatherm sales by classification for the years ended December 31, 1997 and 1996 are presented below:
Sales Dekatherms % Classification 1997 1996 Change
Residential 11,919,843 14,108,058 (15.5) Commercial 10,904,445 11,027,830 (1.1) Industrial 15,729,424 13,909,258 13.1 Transportation gas 2,677,448 3,108,058 (13.9) Total 41,231,160 42,153,204 (2.2)
The gas sales volume decreased for 1997 as a result of milder weather which was offset by increases in contract prices for industrial interruptible customers.
During 1997 the Company recorded a net increase of 4,139 gas customers, increasing its total customers to 252,635.
The Company purchases all of its natural gas from Pipeline Corporation.
The demand for gas is affected by conservation, the weather, the price relationship between gas and alternate fuels and other factors.
The deregulation of natural gas prices at the wellhead and the changes in the prices of natural gas that have occurred under Federal regulation have resulted in the development of a spot market for natural gas in the producing areas of the country. Pipeline Corporation has been successful in purchasing lower cost natural gas in the spot market and arranging for its transportation to South Carolina.
Gas Cost and Supply
Pipeline Corporation purchases natural gas under contracts with producers and marketers on a short-term basis at current price indices and on a long-term basis for reliability assurance at index prices plus a gas inventory charge. The gas is brought to South Carolina through transportation agreements with both Southern Natural and Transco, which expire at various times from 1998 to 2017. The volume of gas which Pipeline Corporation is entitled to transport under these contracts on a firm basis is shown below:
Maximum Daily Supplier Contract Demand Capacity (MCF)
Southern Natural Firm Transportation 188,000 Transco Firm Transportation 105,000 Total 293,000
Under a contract with Pipeline Corporation, the Company's maximum daily contract demand is 224,270 dekatherms. The contract allows the Company to receive amounts in excess of this demand based on availability.
The average cost per MCF of natural gas purchased from Pipeline Corporation was approximately $3.96 in 1997 compared to $4.30 in 1996.
To meet the requirements of the Company and its other high priority natural gas customers during periods of maximum demand, Pipeline Corporation supplements its supplies of natural gas from two LNG plants. The LNG plants are capable of storing the lique- fied equivalent of 1,900,000 MCF of natural gas, of which approximately 1,286,570 MCF were in storage at December 31, 1997. On peak days the LNG plants can regasify up to 150,000 MCF per day. Additionally, Pipeline Corporation had contracted for 6,447,214 MCF of natural gas storage space of which 4,197,154 MCF were in storage on December 31, 1997.
The Company believes that supplies under contract and available for spot market purchase are adequate to meet existing customer demands and to accommodate growth.
Curtailment Plans
The FERC has established allocation priorities applicable to firm and interruptible capacities on interstate pipeline companies which require Southern Natural and Transco to allocate capacity to Pipeline Corporation. The FERC allocation priorities are not applicable to deliveries by the Company to its customers, which are governed by a separate curtailment plan approved by the PSC.
REGULATION
General
The Company is subject to the jurisdiction of the PSC as to retail electric, gas and transit rates, service, accounting, issuance of securities (other than short-term promissory notes) and other matters. The Company is subject to regulation under the Federal Power Act, administered by the FERC and the DOE, in the transmission of electric energy in interstate commerce and in the sale of electric energy at wholesale for resale, as well as with respect to licensed hydroelectric projects and certain other matters, including accounting and the issuance of short-term promissory notes. (See "Capital Requirements and Financing Program").
The Company holds licenses under the Federal Water Power Act or the Federal Power Act with respect to all its hydroelectric projects. The expiration dates of the licenses covering the projects are as follows:
Project Capability (KW) License Expiration Date
Neal Shoals 5,000 2036 Stevens Creek 9,000 2025 Columbia 10,000 2000 Saluda 206,000 2007 Parr Shoals 14,000 2020 Fairfield Pumped Storage 512,000 2020
The Company filed a notice of intent to file an application for a new license for Columbia on June 29, 1995. The application for the new license will be filed by June 30, 1998.
At the termination of a license under the Federal Power Act, the United States government may take over the project covered thereby, or the FERC may extend the license or issue a license to another applicant. If the Federal government takes over a project or the FERC issues a license to another applicant, the original licensee is entitled to be paid its net investment in the project, not to exceed fair value, plus severance damages.
In May 1996 the FERC approved the Company's application establishing open access transmission tariffs and requesting authorization to sell bulk power to wholesale customers at market- based rates.
Nuclear Regulatory Commission
The Company is subject to regulation by the NRC with respect to the ownership and operation of Summer Station. The NRC's jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. In addition, the Federal Emergency Management Agency is responsible for the review, in conjunction with the NRC, of certain aspects of emergency planning relating to the operation of nuclear plants.
Summer Station has received a category one rating from the Institute of Nuclear Power Operations (INPO) in the last five out of six evaluations. The category one rating is the highest given by INPO for a nuclear plant's overall operations.
In 1997 Summer Station successfully completed its refueling outage ahead of schedule and under budget.
In 1996, the NRC completed the Systematic Assessment of Licensee Performance (SALP) for Summer Station. The station was assessed in four functional areas. The results of the assessment identified superior performance in Plant Operations, Maintenance and Engineering and good performance in Plant Support. Superior is the highest assessment given by the NRC.
National Energy Policy Act of 1992 and FERC Orders 636 and 888
The Company's regulated business operations were impacted by the NEPA and FERC Orders No. 636 and 888. NEPA was designed to create a more competitive wholesale power supply market by creating "exempt wholesale generators" and by potentially requiring utilities owning transmission facilities to provide transmission access to wholesalers. See "Competition" for a discussion of FERC Order 888. Order No. 636 was intended to deregulate the markets for interstate sales of natural gas by requiring that pipelines provide transportation services that are equal in quality for all gas suppliers whether the customer purchases gas from the pipeline or another supplier. In the opinion of the Company, it continues to be able to meet successfully the challenges of these altered business climates and does not anticipate there to be any material adverse impact on the results of operations, cash flows, financial position or business prospects.
RATE MATTERS
The following table presents a summary of significant rate activity for the years 1993-1997 based on test years:
REQUESTED GRANTED
Date of % % of General Rate Application/ Amount Increase Date of Amount Increase Applications Hearing (Millions) Requested Order (Millions) Granted
PSC Electric Retail 07/10/95 $ 76.7 8.4% 1/09/96 $67.5 88% Retail 12/07/92 $ 72.0* 11.4% 6/07/93 $60.5 84%
* As modified to reflect lowering of rate of return the Company was seeking.
On January 9, 1996 the PSC issued an order granting the Company an increase in retail electric rates of 7.34%, which was designed to produce additional revenues, based on a test year, of approximately $67.5 million annually. The increase has been implemented in two phases. The first phase, an increase in revenues of approximately $59.5 million annually or 6.47%, commenced in January 1996. The second phase, an increase in revenues of approximately $8.0 million annually, or .87%, was implemented in January 1997. The PSC authorized a return on common equity of 12.0%. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million to be collected through rates over a ten-year period. Additionally, the PSC approved accelerated recovery of a significant portion of the Company's electric regulatory assets (excluding deferred income tax assets) and the remaining transition obligation for postretirement benefits other than pensions, changing the amortization periods to allow recovery by the end of the year 2000. The Company's request to shift, for ratemaking purposes, approximately $257 million of depreciation reserves from transmission and distribution assets to nuclear production assets was also approved. The Consumer Advocate appealed certain issues in the order to the South Carolina Circuit Court, which affirmed the PSC's decisions, and subsequently to the South Carolina Supreme Court which is expected to hear the case and issue a ruling prior to the end of 1998. While the outcome of this proceeding is uncertain, the Company does not believe that any significant adverse changes in the rate order is likely. The PSC's order does not apply to wholesale electric revenues under the FERC's jurisdiction, which constitute approximately two percent of the Company's electric revenues. The FERC rejected the transfer of depreciation reserves for rates subject to its jurisdiction.
In 1994 the PSC issued an order approving the Company's request to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former manufactured gas plants. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for the Company's gas operations that had previously been deferred. In October 1997, as a result of the annual review, the PSC approved the Company's request to increase the billing surcharge from $.006 per therm to $.011 per therm which should enable the Company to recover the remaining balance of $29.6 million by December 2002.
In September 1992 the PSC issued an order granting the Company a $.25 increase in transit fares from $.50 to $.75 in both Columbia and Charleston, South Carolina; however, the PSC also required $.40 fares for low-income customers and denied the Company's request to reduce the number of routes and frequency of service. The new rates were placed into effect in October 1992. The Company appealed the PSC's order to the Circuit Court, which in May 1995 ordered the case back to the PSC for reconsideration of several issues including the low income rider program, routing changes, and the $.75 fare. The Supreme Court declined to review an appeal of the Circuit Court decision and dismissed the case. The PSC and other intervenors filed another Petition for Reconsideration, which the Supreme Court denied. The PSC and other intervenors filed another appeal to the Circuit Court which the Circuit Court denied in an Order dated May 9, 1996. In this Order, the Circuit Court upheld its previous Orders and remanded them back to the PSC. During August 1996, the PSC heard oral arguments on the Orders on remand for the Circuit Court. On September 30, 1996, the PSC issued an order affirming its previous orders and denied the Company's request for reconsideration. The Company has appealed these two PSC orders to the Circuit Court where they are awaiting action.
Fuel Cost Recovery Procedures
The PSC has established a fuel cost recovery procedure which determines the fuel component in the Company's retail electric base rates annually based on projected fuel costs for the ensuing twelve-month period, adjusted for any overcollection or undercollection from the preceding twelve-month period. The Company has the right to request a formal proceeding at any time should circumstances dictate such a review.
In the April 1997 annual review of the fuel cost component of electric rates, the PSC decreased the rate from 13.10 mills per KWH to 12.85 mills per KWH, a monthly decrease of $0.25 for an average customer using 1,000 KWH a month.
The Company's gas rate schedules and contracts include mechanisms which allow it to recover from its customers changes in the actual cost of gas. The Company's firm gas rates allow for the recovery of a fixed cost of gas, based on projections, as established by the PSC in annual gas cost and gas purchase practice hearings. Any differences between actual and projected gas costs are deferred and included when projecting gas costs during the next annual gas cost recovery hearing.
In the October 1997 review the PSC decreased the base cost of gas from 51.260 cents per therm to 48.182 cents per therm which resulted in a monthly decrease of $3.08 (including applicable taxes) based on an average of 100 therms per month on a residential bill during the heating season.
ENVIRONMENTAL MATTERS
General
Federal and state authorities have imposed environmental regulations and standards requirements relating primarily to air emissions, wastewater discharges and solid, toxic and hazardous waste management. Developments in these areas may require that equipment and facilities be modified, supplemented or replaced. The ultimate effect of these regulations and standards upon existing and proposed operations cannot be forecast.
Capital Expenditures
In the years 1995 through 1997, capital expenditures for environmental control amounted to approximately $48.5 million. In addition, approximately $17.1 million, $12.2 million and $10.4 million of environmental control expenditures were made during 1997, 1996 and 1995, respectively, which was included in "Other operation" and "Maintenance" expenses. It is not possible to estimate all future costs for environmental purposes but forecasts for capitalized expenditures are $48.0 million for 1997 and $91.2 million for the four-year period 1999 through 2002. These expenditures are included in the Company's construction program.
Air Quality Control
The Clean Air Act requires electric utilities to reduce emissions of sulfur dioxide and nitrogen oxide by the year 2000. These requirements are being phased in over two periods. The first phase had a compliance date of January 1, 1995 and the second, January 1, 2000. The Company's facilities did not require modifications to meet the requirements of Phase I. The Company will most likely meet the Phase II requirements through the burning of natural gas and/or lower sulfur coal in its generating units and the purchase and use of sulfur dioxide emission allowances. Low nitrogen oxide burners are being installed to reduce nitrogen oxide emissions to the levels required by Phase II. Air toxicity regulations for the electric generating industry are likely to be promulgated around the year 2000.
The Company filed with DHEC compliance plans related to Phase II sulfur dioxide requirements in 1995, and Phase II nitrogen oxide requirements in December, 1997. The Company currently estimates that air emissions control equipment will require capital expenditures of $90.3 million over the 1998-2002 period to retrofit existing facilities, with increased operation and maintenance cost of approximately $1 million per year. To meet compliance requirements through the year 2007, the Company anticipates total capital expenditures of approximately $185 million.
Water Quality Control
The Federal Clean Water Act, as amended, provides for the imposition of effluent limitations that require various levels of treatment for each wastewater discharge. Under this Act, compliance with applicable limitations is achieved under a national permit program. Discharge permits have been issued for all and renewed for nearly all of the Company's and GENCO's generating units. Concurrent with renewal of these permits the permitting agency has implemented a more rigorous program in monitoring and controlling thermal discharges and strategies for toxicity reduction in wastewater streams. The Company has been developing compliance plans to meet these initiatives. Amendments to the Clean Water Act proposed in Congress include several provisions which, if passed, could prove costly to the Company. These include, but are not limited to, limitations to mixing zones and the implementation of technology-based standards.
Comprehensive Environmental Recovery, Compensation and Liability Act (Superfund) and Environmental Assessment Program
The Company has an environmental assessment program to identify and assess current and former operations sites that could require environmental cleanup. As site assessments are initiated an estimate is made of the amount of expenditures, if any, necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated, accrued and actually expended to date for site assessments and cleanup relate primarily to regulated operations; such amounts are deferred and are being amortized and recovered through rates over a five-year period for electric operations and an eight-year period for gas operations. The Company has also recovered portions of its environmental liabilities through settlements with various insurance carriers. Deferred amounts, net of amounts recovered through rates and insurance settlements, totaled $32.4 million and $41.4 million at December 31, 1997 and 1996, respectively. The deferral includes the costs estimated to be associated with the matters discussed below.
In September 1992, the EPA notified the Company, the City of Charleston and the Charleston Housing Authority of their potential liability for the investigation and cleanup of the Calhoun Park area site in Charleston, South Carolina. This site encompasses approximately 30 acres and includes properties which were locations for industrial operations, including a wood preserving (creosote) plant, one of the Company's decommissioned manufactured gas plants, properties owned by the National Park Service and the City of Charleston and private properties. The site has not been placed on the National Priorities List, but may be added before cleanup is initiated. The PRPs have agreed with the EPA to participate in an innovative approach to site investigation and cleanup called "Superfund Accelerated Cleanup Model," allowing the pre- cleanup site investigation process to be compressed significantly. The PRPs have negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study and a corresponding Scope of Work. Field work began in November 1993 and the EPA conditionally approved a Remedial Investigation Report in March 1997. Although the Company is continuing to investigate cost- effective clean-up methodologies, further work is pending EPA approval of the final draft of the Remedial Investigation Report.
In October 1996 the City of Charleston and the Company settled all environmental claims the City may have had against the Company involving the Calhoun Park area for a payment of $26 million over four years (1996-1999) by the Company to the City. The Company is recovering the amount of the settlement, which does not encompass site assessment and cleanup costs, through rates in the same manner as other amounts accrued for site assessments and cleanup as discussed above. As part of the environmental settlement, the Company has agreed to construct an 1,100 space parking garage on the Calhoun Park site and to transfer the facility to the City in exchange for a 20-year municipal bond backed by revenues from the parking garage and a mortgage on the parking garage. Construction is expected to begin in 1998. The total amount of the bond is not to exceed $16.9 million, the maximum expected project cost.
The Company owns three other decommissioned manufactured gas plant sites which contain residues of by-product chemicals. The Company is investigating the sites to monitor the nature and extent of the residual contamination.
Solid Waste Control
The South Carolina Solid Waste Policy and Management Act of 1991 directed the DHEC to promulgate regulations for the disposal of industrial solid waste. DHEC has proposed a regulation, which if adopted as a final regulation in its present form, would significantly increase the Company's costs of construction and operation of existing and future ash management facilities.
Nuclear Fuel Disposal The Nuclear Waste Policy Act of 1982 requires that the United States government make available by 1998 a permanent repository for high-level radioactive waste and spent nuclear fuel and imposes a fee of 1.0 mil per KWH of net nuclear generation after April 7, 1983. Payments, which began in 1983, are subject to change and will extend through the operating life of Summer Station. The Company entered into a contract with the DOE on June 29, 1983, providing for permanent disposal of its spent nuclear fuel by the DOE. The DOE presently estimates that the permanent storage facility will not be available until 2010. The Company has on-site spent nuclear fuel storage capability until at least 2009 and expects to be able to expand its storage capacity to accommodate the spent nuclear fuel output for the life of the plant through rod consolidation, dry cask storage or other technology as it becomes available. The Act also imposes on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available.
OTHER MATTERS
With regard to the Company's insurance coverage for Summer Station, reference is made to Note 10B of Notes to Consolidated Financial Statements which is incorporated herein by reference.
ITEM 2.
ITEM 2. PROPERTIES
The Company's bond indentures, securing the First and Refunding Mortgage Bonds and First Mortgage Bonds issued thereunder, constitute direct mortgage liens on substantially all of its property.
ELECTRIC
The following table gives information with respect to the Company's electric generating facilities.
Net Generating Present Year Capability Facility Fuel Capability Location In-Service (KW)(1)
Steam Urquhart Coal/Gas Beech Island, SC 1953 250,000 McMeekin Coal/Gas Irmo, SC 1958 252,000 Canadys Coal/Gas Canadys, SC 1962 430,000 Wateree Coal Eastover, SC 1970 700,000 Summer (2) Nuclear Parr, SC 1984 635,000 D-Area (3) Coal DOE Savannah River Site, SC 1995 35,000 Cope (4) Coal Cope, SC 1996 408,000
Gas Turbines Burton Gas/Oil Burton, SC 1961 28,500 Faber Place Gas Charleston, SC 1961 9,500 Hardeeville Oil Hardeeville, SC 1968 14,000 Urquhart Gas/Oil Beech Island, SC 1969 38,000 Coit Gas/Oil Columbia, SC 1969 30,000 Parr Gas/Oil Parr, SC 1970 60,000 Williams (5) Gas/Oil Goose Creek, SC 1972 49,000 Hagood Gas/Oil Charleston, SC 1991 95,000
Hydro Neal Shoals Carlisle, SC 1905 5,000 Parr Shoals Parr, SC 1914 14,000 Stevens Creek Martinez, GA 1914 9,000 Columbia Columbia, SC 1927 10,000 Saluda Irmo, SC 1930 206,000
Pumped Storage Fairfield Parr, SC 1978 512,000 Total (6) 3,790,000
(1) Summer rating. (2) Represents the Company's two-thirds portion of the Summer Station. (3) This plant is operated under lease from the DOE and is dispatched to DOE's Savannah River Site steam needs. "Net Generating Capability" for this plant is expected average hourly output. The lease expires on October 1, 2005. (4) Plant began commercial operation in January 1996. (5) The two gas turbines at Williams were purchased upon expiration of the lease on June 29, 1997. (6) Excludes Williams Station.
The Company owns 428 substations having an aggregate transformer capacity of 21,356,393 KVA. The transmission system consists of 3,122 miles of lines and the distribution system consists of 16,129 pole miles of overhead lines and 3,500 trench miles of underground lines.
GAS
Natural Gas
The Company's gas system consists of approximately 11,728 miles of distribution mains and related service facilities.
Propane
The Company has propane air peak shaving facilities which can supplement the supply of natural gas by gasifying propane to yield the equivalent of 102,000 MCF per day of natural gas. These facilities can store the equivalent of 430,405 MCF of natural gas.
TRANSIT
The Company owns 61 motor coaches used in the operation of the Columbia transit system. The Columbia system is comprised of fifteen routes covering 177 miles.
Effective October 1, 1996, the Company transferred ownership and operation of the Charleston transit system to the City of Charleston. As part of the transfer, the Company conveyed ownership to the City of Charleston facilities, equipment and four motor coaches used in the operation of the transit system. The City and the Company entered into an interim operating agreement, with provisions for renewing, whereby the Company will operate the system for the City until a Regional Transit Authority is established. The Company and the City have agreed upon a rate structure designed to allow the Company to recover its costs of operating the Charleston transit system. The Charleston system is composed of fourteen routes covering 110 miles.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
For information regarding legal proceedings, see ITEM 1., "BUSINESS - RATE MATTERS" and "BUSINESS - ENVIRONMENTAL MATTERS - Comprehensive Environmental Recovery, Compensation and Liabilities Act (Superfund) and Environmental Assessment Program" and Note 10 of Notes to Consolidated Financial Statements appearing in Item 8., "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA."
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not Applicable
PART II
ITEM 5.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
All of the Company's common stock is owned by SCANA and therefore there is no market for such stock. During 1997 and 1996 the Company paid $141.4 million and $132.9 million, respectively, in cash dividends to SCANA.
SECURITIES RATINGS (As of December 31, 1997)
SOUTH CAROLINA ELECTRIC & GAS COMPANY First First and Trust Rating Mortgage Refunding Preferred Preferred Commercial Agency Bonds Mortgage Bonds Stock Securities Paper
Duff & Phelps A+ A+ A - D-1
Moody's A1 A1 a2 a2 P-1
Standard & Poor's A A A- A- A-1
Further reference is made to Note 5 of Notes to Consolidated Financial Statements.
The Restated Articles of Incorporation of the Company and the Indenture underlying its First and Refunding Mortgage Bonds contain provisions that may limit the payment of cash dividends on common stock. In addition, with respect to hydroelectric projects, the Federal Power Act may require the appropriation of a portion of the earnings therefrom. At December 31, 1997 approximately $21.5 million of retained earnings were restricted as to payment of cash dividends on common stock.
While a decrease in market interest rates would increase the fair value of debt, it is unlikely that events which would result in a realized loss will occur.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
Independent Auditors' Report....................................... 34
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1997 and 1996... 35
Consolidated Statements of Income and Retained Earnings for the years ended December 31, 1997, 1996 and 1995............. 37
Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995............................. 38
Consolidated Statements of Capitalization as of December 31, 1997 and 1996................................... 39
Notes to Consolidated Financial Statements..................... 41
Supplemental financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the consolidated financial statements or in the notes thereto.
INDEPENDENT AUDITORS' REPORT
South Carolina Electric & Gas Company:
We have audited the accompanying Consolidated Balance Sheets and Statements of Capitalization of South Carolina Electric & Gas Company (Company) as of December 31, 1997 and 1996 and the related Consolidated Statements of Income and Retained Earnings and of Cash Flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1997 and 1996 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted accounting principles.
s/Deloitte & Touche LLP DELOITTE & TOUCHE LLP Columbia, South Carolina February 9, 1998
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. Organization and Principles of Consolidation
The Company, a public utility, is a South Carolina corporation organized in 1924 and a wholly owned subsidiary of SCANA Corporation (SCANA), a South Carolina holding company. The Company is engaged predominately in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.
The accompanying Consolidated Financial Statements include the accounts of the Company, South Carolina Fuel Company, Inc. (Fuel Company) and SCE&G Trust I. (See Note 1N.) Intercompany balances and transactions between the Company, Fuel Company and SCE&G Trust I have been eliminated in consolidation.
Affiliated Transactions
The Company has entered into agreements with certain affiliates to purchase gas for resale to its distribution customers and to purchase electric energy. The Company purchases all of its natural gas requirements from Pipeline Corporation and at December 31, 1997 and 1996 the Company had approximately $22.1 million and $22.3 million, respectively, payable to Pipeline Corporation for such gas purchases. The Company purchases all of the electric generation of Williams Station, which is owned by GENCO, under a unit power sales agreement. At December 31, 1997 and 1996 the Company had approximately $9.1 million and $8.6 million, respectively, payable to GENCO for unit power purchases. Such unit power purchases, which are included in "Purchased power," amounted to approximately $99.8 million, $95.3 million and $83.5 million in 1997, 1996 and 1995, respectively.
Total interest income, based on market interest rates, associated with the Company's advances to affiliated companies was approximately $20,000, $36,000 and $174,000 in 1997, 1996 and 1995, respectively.
In 1997 and 1996 there were no amounts relating to advances from affiliated companies included in "Other interest expense"; however, for 1995 $114,000 was included. Intercompany interest is calculated at market rates.
B. Basis of Accounting
The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statements of Financial Accounting Standards No. 71 (SFAS 71). The accounting standard requires cost-based rate-regulated utilities to recognize in their financial statements revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result the Company has recorded, as of December 31, 1997, approximately $236 million and $62 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $118 million and $52 million, respectively. The electric and gas regulatory assets of approximately $71 million and $44 million, respectively (excluding deferred income tax assets) are being recovered through rates and, as discussed in Note 2A, the Public Service Commission of South Carolina (PSC) has approved accelerated recovery of approximately $45 million of the electric regulatory assets. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and would be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations in the period the write-off is recorded, but it is not expected that cash flows or financial position would be materially affected.
C. System of Accounts
The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and as adopted by the PSC.
D. Utility Plant
Utility plant is stated substantially at original cost. The costs of additions, renewals and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged, along with the cost of removal, less salvage, to accumulated depreciation. The costs of repairs, replacements and renewals of items of property determined to be less than a unit of property are charged to maintenance expense.
The Company, operator of the V. C. Summer Nuclear Station (Summer Station), and the South Carolina Public Service Authority (PSA) are joint owners of Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to the Company's portion of Summer Station was approximately $978.2 million and $937.2 million as of December 31, 1997 and 1996, respectively. Accumulated depreciation associated with the Company's share of Summer Station was approximately $323.6 million and $313.2 million as of December 31, 1997 and 1996, respectively. The Company's share of the direct expenses associated with operating Summer Station is included in "Other operation" and "Maintenance" expenses.
E. Allowance for Funds Used During Construction
AFC, a noncash item, reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company has calculated AFC using composite rates of 8.8%, 8.1% and 8.6% for 1997, 1996 and 1995, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process and sulfur dioxide emission allowances is capitalized at the actual interest amount.
F. Revenue Recognition
Customers' meters are read and bills are rendered on a monthly cycle basis. Base revenue is recorded during the accounting period in which the meters are read.
Fuel costs for electric generation are collected through the fuel cost component in retail electric rates. The fuel cost component contained in electric rates is established by the PSC during annual fuel cost hearings. Any difference between actual fuel costs and that contained in the fuel cost component is deferred and included when determining the fuel cost component during the next annual fuel cost hearing. The Company had undercollected through the electric fuel cost component approximately $1.3 million and at December 31, 1997 and overcollected approximately $ 1.9 million December 31, 1996 which are included in "Deferred Debits - Other" and "Deferred Credits - Other," respectively.
Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the PSC during annual gas cost recovery hearings. Any difference between actual gas cost and that contained in the rates is deferred and included when establishing gas costs during the next annual gas cost recovery hearing. At December 31, 1997 and 1996 the Company had undercollected through the gas cost recovery procedure approximately $7.6 million and $10.9 million, respectively, which are included in "Deferred Debits - Other."
The Company's gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment, which minimizes fluctuations in gas revenues due to abnormal weather conditions.
G. Depreciation and Amortization Provisions for depreciation are recorded using the straight- line method for financial reporting purposes and are based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates were 3.09%, 3.13% and 3.02% for 1997, 1996 and 1995, respectively.
Nuclear fuel amortization, which is included in "Fuel used in electric generation" and is recovered through the fuel cost component of the Company's rates, is recorded using the units-of- production method. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the Department Of Energy (DOE) under a contract for disposal of spent nuclear fuel.
The acquisition adjustment relating to the purchase of certain gas properties in 1982 is being amortized over a 40-year period using the straight-line method.
H. Nuclear Decommissioning
Decommissioning of Summer Station is presently scheduled to commence when the operating license expires in the year 2022. Based on a 1991 study, the expenditures (on a before-tax basis) related to the Company's share of decommissioning activities are estimated, in 2022 dollars assuming a 4.5% annual rate of inflation, to be $545.3 million including partial reclamation costs. The Company is providing for its share of estimated decommissioning costs of Summer Station over the life of Summer Station. The Company's method of funding decommissioning cost is referred to as COMReP (Cost of Money Reduction Plan). Under this plan, funds collected through rates ($3.2 million in 1997 and 1996) are used to pay premiums on insurance policies on the lives of certain Company personnel. The Company is the beneficiary of these policies. Through these insurance contracts, the Company is able to take advantage of income tax benefits and accrue earnings on the fund on a tax-deferred basis at a rate higher than can be achieved using more traditional funding approaches. Amounts for decommissioning collected through electric rates, insurance proceeds, and interest on proceeds less expenses are transferred by the Company to an external trust fund in compliance with the financial assurance requirements of the Nuclear Regulatory Commission. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis. The trust's sources of decommissioning funds under the COMReP program include investment components of life insurance policy proceeds, return on investment and the cash transfers from the Company described above. The Company records its liability for decommissioning costs in deferred credits.
Pursuant to the National Energy Policy Act passed by Congress in 1992 and the requirements of the DOE, the Company has recorded a liability for its estimated share of the DOE's decontamination and decommissioning obligation. The liability, approximately $4.0 million at December 31, 1997, has been included in "Long-Term Debt, Net." The Company is recovering the cost associated with this liability through the fuel cost component of its rates; accordingly, this amount has been deferred and is included in "Deferred Debits - Other."
I. Income Taxes
Deferred tax assets and liabilities are recorded for the tax effects of temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense.
J. Pension Expense
The Company participates in SCANA's noncontributory defined benefit pension plan, which covers all permanent employees. Benefits are based on years of accredited service and the employee's average annual base earnings received during the last three years of employment. SCANA's policy has been to fund the plan to the extent permitted by the applicable Federal income tax regulations as determined by an independent actuary.
Net periodic pension cost for the years ended December 31, 1997, 1996 and 1995 included the following components:
1997 1996 1995 (Millions of Dollars) Service cost--benefits earned during the period $ 6.8 $ 6.5 $ 5.2 Interest cost on projected benefit obligation 23.5 22.0 19.5 Adjustments: Return on plan assets (119.5) (78.6) (103.9) Net amortization and deferral 72.8 40.1 74.8 Amounts contributed by the Company's affiliates (0.6) (0.3) (0.2) Net periodic pension (income) expense $(17.0) $(10.3) $ (4.6)
The determination of net periodic pension cost is based upon the following assumptions:
1997 1996 1995 Annual discount rate 7.5% 7.5% 8.0% Expected long-term rate of return on plan assets 8.0% 8.0% 8.0% Annual rate of salary increases 3.0% 3.0% 2.5%
The following table sets forth the funded status of the plan at December 31, 1997 and 1996:
1997 1996 (Millions of Dollars) Actuarial present value of benefit obligations: Vested benefit obligation $259.7 $243.9 Nonvested benefit obligation 25.4 23.7 Accumulated benefit obligation $285.1 $267.6
Plan assets at fair value (invested primarily in equity and debt securities) $632.9 $523.5 Projected benefit obligation 344.4 306.9 Plan assets greater than projected benefit obligation 288.5 216.6 Unrecognized net transition liability 7.4 8.2 Unrecognized prior service costs 13.4 8.2 Unrecognized net gain (227.1) (175.1) Pension asset recognized in Consolidated Balance Sheets $ 82.2 $ 57.9
The accumulated benefit obligation is based on the plan's benefit formulas without considering expected future salary increases. The following table sets forth the assumptions used in determining the amounts shown above for the years 1997 and 1996.
1997 1996
Annual discount rate used to determine benefit obligations 7.5% 7.5% Assumed annual rate of future salary increases for projected benefit obligation 4.0% 3.0%
In addition to pension benefits, the Company provides certain health care and life insurance benefits to active and retired employees. The costs of postretirement benefits other than pensions are accrued during the years the employees render the service necessary to be eligible for the applicable benefits. The Company expensed approximately $8.1 million, $9.8 million and $8.5 million, net of payments to current retirees, for the years ended December 31, 1997, 1996 and 1995, respectively. Additionally, to accelerate the amortization of the remaining transition obligation for postretirement benefits other than pensions, as authorized by the PSC, the Company expensed approximately $15.6 million and $6.2 million for the years ended December 31, 1997 and 1996, respectively. (See Note 2A.)
Net periodic postretirement benefit cost for the years ended December 31, 1997, 1996 and 1995, included the following components:
1997 1996 1995 (Millions of Dollars)
Service cost--benefits earned during the period $ 2.5 $ 2.6 $ 2.1 Interest cost on accumulated postretirement benefit obligation 7.8 7.8 7.2 Adjustments: Return on plan assets - - - Amortization of unrecognized transition obligation 18.9 9.5 3.3 Other net amortization and deferral 0.8 1.2 0.7 Amounts contributed by the Company's affiliates (1.1) (0.7) (0.6) Net periodic postretirement benefit cost $28.9 $20.4 $12.7
The determination of net periodic postretirement benefit cost is based upon the following assumptions:
1997 1996 1995
Annual discount rate 7.5% 7.5% 8.0% Health care cost trend rate 9.0% 9.5% 11.0% Ultimate health care cost trend rate (to be achieved in 2004) 5.5% 5.5% 6.0%
The following table sets forth the funded status of the plan at December 31, 1997 and 1996:
1997 1996 (Millions of Dollars)
Accumulated postretirement benefit obligations for: Retirees $ 76.7 $ 74.2 Other fully eligible participants 5.9 6.6 Other active participants 26.2 29.3 Accumulated postretirement benefit obligation 108.8 110.1
Plan assets at fair value - - Accumulated postretirement benefit obligation 108.8 110.1 Plan assets less than accumulated postretirement benefit obligation (108.8) (110.1) Unrecognized net transition liability 29.8 48.7 Unrecognized prior service costs 5.8 6.2 Unrecognized net loss 12.2 17.8 Postretirement benefit liability recognized in Consolidated Balance Sheets $ (61.0) $ (37.4)
The accumulated postretirement benefit obligation is based upon the plan's benefit provisions and the following assumptions:
1997 1996 Assumed health care cost trend rate used to measure expected costs 9.0% 9.5% Ultimate health care cost trend rate (to be achieved in 2004) 5.5% 5.5% Annual discount rate 7.5% 7.5% Annual rate of salary increases 4.0% 3.0%
The effect of a one percentage-point increase in the assumed health care cost trend rate for each future year on the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year ended December 31, 1997 and the accumulated postretirement benefit obligation as of December 31, 1997 would be to increase such amounts by $0.2 million and $3.2 million, respectively.
K. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
For regulatory purposes, long-term debt premium, discount and expense are being amortized as components of "Interest on long-term debt, net" over the terms of the respective debt issues. Gains or losses on reacquired debt that is refinanced are deferred and amortized over the term of the replacement debt.
L. Environmental
The Company has an environmental assessment program to identify and assess current and former operating sites that could require environmental cleanup. As site assessments are initiated an estimate is made of the amount of expenditures, if any, necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated, accrued and actually expended to date for site assessments and cleanup relate primarily to regulated operations; such amounts are deferred and are being amortized and recovered through rates over a five-year period for electric operations and an eight-year period for gas operations. The Company has also recovered portions of its environmental liabilities through settlements with various insurance carriers. Deferred amounts, net of amounts recovered through rates and insurance settlements, totaled $32.4 million and $41.4 million at December 31, 1997 and 1996, respectively. The deferral includes the estimated costs to be associated with the matters discussed in Note 10C.
M. Fuel Inventories
Nuclear fuel and fossil fuel inventories and sulfur dioxide emission allowances are purchased and financed by Fuel Company under a contract which requires the Company to reimburse Fuel Company for all costs and expenses relating to the ownership and financing of fuel inventories and sulfur dioxide emission allowances. Accordingly, such fuel inventories and emission allowances and fuel-related assets and liabilities are included in the Company's consolidated financial statements. (See Note 4.)
N. Temporary Cash Investments
The Company considers temporary cash investments having original maturities of three months or less to be cash equivalents. Temporary cash investments are generally in the form of commercial paper, certificates of deposit and repurchase agreements. O. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the 1997 presentation.
P. Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
2. RATE MATTERS:
A. On January 9, 1996 the PSC issued an order granting the Company an increase in retail electric rates of 7.34%, which was designed to produce additional revenues, based on a test year, of approximately $67.5 million annually. The increase has been implemented in two phases. The first phase, an increase in revenues of approximately $59.5 million annually or 6.47%, commenced in January 1996. The second phase, an increase in revenues of approximately $8.0 million annually, or .87%, was implemented in January 1997. The PSC authorized a return on common equity of 12.0%. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million to be collected through rates over a ten-year period. Additionally, the PSC approved accelerated recovery of a significant portion of the Company's electric regulatory assets (excluding deferred income tax assets) and the remaining transition obligation for postretirement benefits other than pensions, changing the amortization periods to allow recovery by the end of the year 2000. The Company's request to shift, for ratemaking purposes, approximately $257 million of depreciation reserves from transmission and distribution assets to nuclear production assets was also approved. The Consumer Advocate appealed certain issues in the order to the South Carolina Circuit Court, which affirmed the PSC's decisions, and subsequently to the South Carolina Supreme Court which is expected to hear the case and issue a ruling prior to the end of 1998. While the outcome of this proceeding is uncertain, the Company does not believe that any significant adverse changes in the rate order is likely. The PSC's order does not apply to wholesale electric revenues under the FERC's jurisdiction, which constitute approximately two percent of the Company's electric revenues. The FERC rejected the transfer of depreciation reserves for rates subject to its jurisdiction.
B. In 1994 the PSC issued an order approving the Company's request to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former manufactured gas plants. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for the Company's gas operations that had previously been deferred. In October 1997, as a result of the annual review, the PSC approved the Company's request to increase the billing surcharge from $.006 per therm to $.011 per therm which should enable the Company to recover the remaining balance of $29.6 million by December 2002.
C. In September 1992 the PSC issued an order granting the Company a $.25 increase in transit fares from $.50 to $.75 in both Columbia and Charleston, South Carolina; however, the PSC also required $.40 fares for low income customers and denied the Company's request to reduce the number of routes and frequency of service. The new rates were placed into effect in October 1992. The Company appealed the PSC's order to the Circuit Court, which in May 1995 ordered the case back to the PSC for reconsideration of several issues including the low income rider program, routing changes, and the $.75 fare. The Supreme Court declined to review an appeal of the Circuit Court decision and dismissed the case. The PSC and other intervenors filed another Petition for Reconsideration, which the Supreme Court denied. The PSC and other intervenors filed another appeal to the Circuit Court which the Circuit Court denied in an order dated May 9, 1996. In this order, the Circuit Court upheld its previous orders and remanded them to the PSC. During August 1996, the PSC heard oral arguments on the orders on remand from the Circuit Court. On September 30, 1996, the PSC issued an order affirming its previous orders and denied the Company's request for reconsideration. The Company has appealed these two PSC orders to the Circuit Court where they are awaiting action.
3. LONG-TERM DEBT:
The annual amounts of long-term debt maturities, including amounts due under nuclear and fossil fuel agreements (see Note 4), and sinking fund requirements for the years 1998 through 2002 are summarized as follows: Year Amount Year Amount (Millions of Dollars)
1998 $ 47.7 2001 $ 21.3 1999 27.8 2002 51.3 2000 201.5
Approximately $17.2 million of the portion of long-term debt payable in 1998 may be satisfied by either deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits, or by deposit of cash with the Trustee.
On August 7, 1996 the City of Charleston executed 30-year electric and gas franchise agreements with the Company. In consideration for the electric franchise agreement, the Company is paying the City $25 million over seven years (1996 through 2002) and has donated to the City the existing transit assets in Charleston. The $25 million is included in electric plant-in- service. In settlement of environmental claims the City may have had against the Company involving the Calhoun Park area, where the Company and its predecessor companies operated a manufactured gas plant until the 1960's, the Company is paying the City $26 million over a four-year period (1996 through 1999). Such amount is deferred (see Note 1L). The unpaid balances of these amounts are included in "Long-Term Debt."
The Company has three-year revolving lines of credit totaling $75 million, in addition to other lines of credit, that provide liquidity for issuance of commercial paper. The three- year lines of credit provide back-up liquidity when commercial paper outstanding is in excess of $175 million. The long-term nature of the lines of credit allow commercial paper in excess of $175 million to be classified as long-term debt. The Company had outstanding commercial paper of $13.3 million and $90 million at December 31, 1997 and 1996, at weighted average interest rates of 5.90% and 5.53%, respectively.
Substantially all utility plant and fuel inventories are pledged as collateral in connection with long-term debt.
4. FUEL FINANCINGS:
Nuclear and fossil fuel inventories and sulfur dioxide emission allowances are financed through the issuance by Fuel Company of short-term commercial paper. These short-term borrowings are supported by an irrevocable revolving credit agreement which expires December 19, 2000. Accordingly, the amounts outstanding have been included in long-term debt. The credit agreement provides for a maximum amount of $125 million that may be outstanding at any time.
Commercial paper outstanding totaled $80.3 million and $66.1 million at December 31, 1997 and 1996 at weighted average interest rates of 5.87% and 5.62%, respectively.
5. COMMON EQUITY:
The changes in "Stockholders' Investment" (Including Preferred Stock Not Subject to Purchase or Sinking Funds) during 1997, 1996 and 1995 are summarized as follows:
Common Preferred Millions Shares Shares of Dollars Balance December 31, 1994 40,296,147 322,877 $1,159.5 Changes in Retained Earnings: Net Income 169.2 Cash Dividends Declared: Preferred Stock (at stated rates) (5.7) Common Stock (121.4) Equity Contributions from Parent 139.5 Balance December 31, 1995 40,296,147 322,877 1,341.1 Changes in Retained Earnings: Net Income 190.5 Cash Dividends Declared: Preferred Stock (at stated rates) (5.4) Common Stock (135.8) Equity Contributions from Parent including transfer of assets 49.1 Balance December 31, 1996 40,296,147 322,877 1,439.5 Changes in Retained Earnings: Net Income 194.6 Cash Dividends Declared: Preferred Stock (at stated rates) (9.3) Common Stock (162.6) Equity Contributions from Parent 12.1 Issuance of Preferred Stock 1,000,000 100.0 Redemption of Preferred Stock (197,668) (19.8) Changes in Capital Stock Expense 0.1 Changes in Loss on Resale of Reacquired Stock (1.6) Balance December 31, 1997 40,296,147 1,125,209 $1,553.0
The Restated Articles of Incorporation of the Company and the Indenture underlying its First and Refunding Mortgage Bonds contain provisions that under certain circumstances could limit the payment of cash dividends on common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of the earnings therefrom. At December 31, 1997 approximately $21.5 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.
6. PREFERRED STOCK:
The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. Retirements under sinking fund requirements are at par values.
The aggregate annual amount of purchase fund or sinking fund requirements for preferred stock for the years 1998 through 2002 is $0.6 million.
The changes in "Total Preferred Stock (Subject to Purchase or Sinking Funds)" during 1997, 1996 and 1995 are summarized as follows:
Number Millions of Shares of Dollars
Balance December 31, 1994 822,094 $ 51.9 Shares Redeemed: $100 par value (6,809) (0.7) $50 par value (51,666) (2.5) Balance December 31, 1995 763,619 48.7 Shares Redeemed: $100 par value (7,198) (0.7) $50 par value (50,319) (2.6) Balance December 31, 1996 706,102 45.4 Shares Redeemed: $100 par value (202,812) (20.3) $50 par value (252,196) (12.6) Balance December 31, 1997 251,094 $ 12.5
On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly- owned subsidiary of the Company, issued $50 million (2,000,000 shares) of 7.55% Trust Preferred Securities, Series A (the "Preferred Securities"). The Company owns all of the Common Securities of the Trust (the "Common Securities"). The Preferred Securities and the Common Securities (the "Trust Securities") represent undivided beneficial ownership interests in the assets of the Trust. The Trust exists for the sole purpose of issuing the Trust Securities and using the proceeds thereof to purchase from the Company its 7.55% Junior Subordinated Debentures due September 30, 2027. The sole asset of the Trust is $50 million of Junior Subordinated Debentures of the Company. Accordingly, no financial statements of the Trust are presented. The Company's obligations under the Guarantee Agreement entered into in connection with the Preferred Securities, when taken together with the Company's obligation to make interest and other payments on the Junior Subordinated Debentures issued to the Trust and the Company's obligations under its Indenture pursuant to which the Junior Subordinated Debentures are issued, provides a full and unconditional guarantee by the Company of the Trust's obligations under the Preferred Securities. Proceeds were used to redeem preferred stock of the Company.
The preferred securities of the Trust are redeemable only in conjunction with the redemption of the related 7.55% Junior Subordinated Debentures. The Junior Subordinated Debentures will mature on September 30, 2027 and may be redeemed, in whole or in part, at any time on or after September 30, 2002 or upon the occurrence of a Tax Event. A Tax Event occurs if an opinion is received from counsel experienced in such matters that there is more than an insubstantial risk that: (1) the Trust is or will be subject to Federal income tax, with respect to income received or accrued on the Junior Subordinated Debentures, (2) interest payable by the Company on the Junior Subordinated Debentures will not be deductible, in whole or in part, by the Company for Federal income tax purposes, and (3) the Trust will be subject to more than a de minimis amount of other taxes, duties, or other governmental charges.
Upon the redemption of the Junior Subordinated Debentures, payment will simultaneously be applied to redeem Preferred Securities having an aggregate liquidation amount equal to the aggregate principal amount of the Junior Subordinated Debentures. The Preferred Securities are redeemable at $25 per preferred security plus accrued distributions.
7. INCOME TAXES:
Total income tax expense for 1997, 1996 and 1995 is as follows:
1997 1996 1995 (Millions of Dollars) Current taxes: Federal $ 88.0 $ 88.2 $ 94.1 State (6.9) 13.1 14.3 Total current taxes 81.1 101.3 108.4 Deferred taxes, net: Federal 3.7 8.3 (7.3) State 1.5 1.8 (0.6) Total deferred taxes 5.2 10.1 (7.9) Investment tax credits: Deferred - State 19.0 - - Amortization of amounts deferred-State (1.5) - - Amortization of amounts deferred-Federal (3.2) (3.2) (3.2) Total Investment Tax credit 14.3 (3.2) (3.2) Total income tax expense $100.6 $108.2 $ 97.3
The difference in total income tax expense and the amount calculated from the application of the statutory Federal income tax rate (35% for 1997, 1996 and 1995) to pre-tax income is reconciled as follows:
1997 1996 1995 (Millions of Dollars)
Net income $194.7 $190.5 $169.2 Total income tax expense: Charged to operating expenses 98.1 107.7 97.0 Charged (credited) to other items 2.5 0.5 0.3 Total pre-tax income $295.3 $298.7 $266.5
Income taxes on above at statutory Federal income tax rate $103.4 $104.5 $ 93.3 Increases (decreases) attributable to: State income taxes (less Federal income tax effect) 7.9 9.7 8.9 Deferred income tax reversal at higher than statutory rates (3.5) (3.4) (3.3) Amortization of Federal investment tax credits (3.2) (3.2) (3.2) Allowance for equity funds used during construction (2.1) (1.4) (3.3) Other differences, net (1.9) 2.0 4.9 Total income tax expense $100.6 $108.2 $ 97.3
The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $518.5 million at December 31, 1997 and $501.7 million at December 31, 1996 are as follows:
1997 1996 (Millions of Dollars) Deferred tax assets: Unamortized investment tax credits $ 55.4 $ 46.5 Cycle billing 20.5 19.8 Nuclear operations expenses 3.1 4.7 Deferred compensation 6.7 6.6 Other postretirement benefits 14.6 10.8 Other 8.1 6.6 Total deferred tax assets 108.4 95.0 Deferred tax liabilities: Property plant and equipment 561.2 540.9 Pension expense 27.5 21.8 Reacquired debt 7.5 8.3 Research and experimentation 19.5 12.5 Deferred fuel 3.6 3.7 Other 7.6 9.5 Total deferred tax liabilities 626.9 596.7 Net deferred tax liability $518.5 $501.7
The Internal Revenue Service has examined and closed consolidated Federal income tax returns of SCANA Corporation through 1989, and has examined and proposed adjustments to SCANA's Federal returns for 1990 through 1995. The Company does not anticipate that any adjustments which might result from these examinations will have a significant impact on the results of operations, cash flows or financial position of the Company.
8. FINANCIAL INSTRUMENTS:
The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 1997 and 1996 are as follows:
The information presented herein is based on pertinent information available to the Company as of December 31, 1997 and 1996. Although the Company is not aware of any factors that would significantly affect the estimated fair value amounts, such financial instruments have not been comprehensively revalued since December 31, 1997, and the current estimated fair value may differ significantly from the estimated fair value at that date.
The following methods and assumptions were used to estimate the fair value of the above classes of financial instruments:
Cash and temporary cash investments, including commercial paper, repurchase agreements, treasury bills and notes, are valued at their carrying amount.
Fair values of investments and long-term debt are based on quoted market prices of the instruments or similar instruments, or for those instruments for which there are no quoted market prices available, fair values are based on net present value calculations. Investments which are not considered to be financial instruments have been excluded from the carrying amount and estimated fair value. Settlement of long term debt may not be possible or may not be a prudent management decision.
Short-term borrowings are valued at their carrying amount.
The fair value of preferred stock (subject to purchase or sinking funds) is estimated on the basis of market prices.
Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been taken into consideration.
9. SHORT-TERM BORROWINGS:
The Company pays fees to banks as compensation for its committed lines of credit. Commercial paper borrowings are for 270 days or less. Details of lines of credit (including uncommitted lines of credit) and short-term borrowings, excluding amounts classified as long-term (Notes 3 and 4), at December 31, 1997 and 1996 and for the years then ended are as follows:
1997 1996 (Millions of dollars)
Authorized lines of credit at year-end $315 $145.0 Unused lines of credit at year-end $315 $145.0 Short-term borrowings outstanding at year-end: Commercial paper $13.3 $ 90.0 Weighted average interest rate 5.90% 5.53%
10. COMMITMENTS AND CONTINGENCIES:
A. Construction
SCANA and Westvaco Corporation have formed a limited liability company, Cogen South LLC, to build and operate a $170 million cogeneration facility at Westvaco's Kraft Division Paper Mill in North Charleston, South Carolina. SCANA and Westvaco each own a 50% interest in LLC. The facility will provide industrial process steam for the Westvaco paper mill and shaft horsepower to enable the Company to generate up to 99 megawatts of electricity. In addition to the cogeneration LLC, Westvaco has entered into a 20-year contract with the Company for all its electricity requirements at the North Charleston mill at the Company's standard industrial rate. Construction of the plant began in September 1996 and it is expected to be operational in the fall of 1998.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with public liability for a nuclear incident, currently establishes the liability limit for third-party claims associated with any nuclear incident at $8.9 billion. Each reactor licensee is currently liable for up to $79.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $10 million of the liability per reactor would be assessed per year. The Company's maximum assessment, based on its two-thirds ownership of Summer Station, would be approximately $52.9 million per incident, but not more than $6.7 million per year.
The Company currently maintains policies (for itself and on behalf of the PSA) with Nuclear Electric Insurance Limited (NEIL) and American Nuclear Insurers (ANI) providing combined property and decontamination insurance coverage of $2.0 billion for any losses at Summer Station. The Company pays annual premiums and, in addition, could be assessed a retroactive premium not to exceed five times its annual premium in the event of property damage loss to any nuclear generating facilities covered under the NEIL program. Based on the current annual premium, this retroactive premium would not exceed $5.1 million.
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that the Company's rates would not recover the cost of any purchased replacement power, the Company will retain the risk of loss as a self-insurer. The Company has no reason to anticipate a serious nuclear incident at Summer Station. If such an incident were to occur, it could have a material adverse impact on the Company's results of operations, cash flows and financial position.
C. Environmental
In September 1992, the EPA notified the Company, the City of Charleston and the Charleston Housing Authority of their potential liability for the investigation and cleanup of the Calhoun Park area site in Charleston, South Carolina. This site encompasses approximately 30 acres and includes properties which were locations for industrial operations, including a wood preserving (creosote) plant, one of the Company's decommissioned manufactured gas plants, properties owned by the National Park Service and the City of Charleston and private properties. The site has not been placed on the National Priorities List, but may be added before cleanup is initiated. The PRPs have agreed with the EPA to participate in an
innovative approach to site investigation and cleanup called "Superfund Accelerated Cleanup Model," allowing the pre-cleanup site investigation process to be compressed significantly. The PRPs have negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study and a corresponding Scope of Work. Field work began in November 1993 and the EPA conditionally approved a Remedial Investigation Report in March 1997. Although the Company is continuing to investigate cost-effective clean-up methodologies, further work is pending EPA approval of the final draft of the Remedial Investigation Report. See Note 1L.
In October 1996 the City of Charleston and the Company settled all environmental claims the City may have had against the Company involving the Calhoun Park area for a payment of $26 million over four years (1996 through 1999) by the Company to the City. The Company is recovering the amount of the settlement, which does not encompass site assessment and cleanup costs, through rates in the same manner as other amounts accrued for site assessments and cleanup as discussed above. See Note 1L. As part of the environmental settlement, the Company has agreed to construct an 1,100 space parking garage on the Calhoun Park site and to transfer the facility to the City in exchange for a 20-year municipal bond backed by revenues from the parking garage and a mortgage on the parking garage. Construction is expected to begin in 1998. The total amount of the bond is not to exceed $16.9 million, the maximum expected project cost.
The Company owns three other decommissioned manufactured gas plant sites which contain residues of by-product chemicals. The Company is investigating the sites to monitor the nature and extent of the residual contamination.
D. Franchise Agreements
See Note 3 for a discussion of an electric franchise agreement between the Company and the City of Charleston.
E. Claims and Litigation
The Company is engaged in various claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company. No estimate of the range of loss from these matters can currently be determined.
11. SEGMENT OF BUSINESS INFORMATION:
Segment information at December 31, 1997, 1996 and 1995 and for the years then ended is as follows:
Electric Gas Transit Total (Millions of Dollars) Operating revenues $1,103 $234 $ 1 $1,338 Operating expenses, excluding depreciation and amortization 710 201 5 916 Depreciation and amortization 129 11 - 140 Total operating expenses 839 212 5 1,056 Operating income (loss) $ 264 $ 22 $(4) 282
Add - Other income, net 9 Less - Interest charges, net 95 Less - Preferred Dividend Requirements, including the Company - Obligated Mandatorily Redeemable Preferred Securities 10 Net income $ 186
Capital expenditures: Identifiable $218 $ 15 $ - $ 233
Utilized for overall Company operations 32 Total $ 265
Identifiable assets at December 31, 1997: Utility plant, net $2,951 $221 $ 2 $3,174 Inventories 69 2 - 71 Total $3,020 $223 $ - 3,245
Other assets 809 Total assets $4,054
Electric Gas Transit Total (Millions of Dollars) Operating revenues $1,107 $ 235 $ 3 $1,345 Operating expenses, excluding depreciation and amortization 711 204 9 924 Depreciation and amortization 123 12 - 135 Total operating expenses 834 216 9 1,059 Operating income (loss) $ 273 $ 19 $(6) 286
Add - Other income, net 4 Less - Interest charges, net 9 Less - Preferred stock dividends 6 Net income $ 185
Capital expenditures: Identifiable $ 197 $ 19 $ - $ 216
Utilized for overall Company operations 24 Total 240
Identifiable assets at December 31, 1996: Utility plant, net $2,870 $ 217 $ 2 $3,089 Inventories 76 2 - 78 Total $2,946 $ 219 $ 2 3,167
Other assets 792 Total assets $3,959
Electric Gas Transit Total (Thousands of Dollars) Operating revenues $1,006 $ 201 $ 4 $1,211 Operating expenses, excluding depreciation and amortization 657 170 10 837 Depreciation and amortization 104 13 1 118 Total operating expenses 761 183 11 955 Operating income (loss) $ 245 $ 18 $(7) 256
Add - Other income, net 9 Less - Interest charges, net 96 Less - Preferred stock dividends 6 Net income $ 163
Capital expenditures: Identifiable $ 245 $ 20 $ - $ 265
Utilized for overall Company operations 28 Total $ 293
Identifiable assets at December 31, 1995: Utility plant, net $2,851 $ 210 $ 2 $3,063 Inventories 77 2 - 79 Total $2,928 $ 212 $ 2 3,142
Other assets 661 Total assets $3,803
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
(Millions of Dollars) First Second Third Fourth Quarter Quarter Quarter Quarter Annual Total operating revenues $337 $289 $377 $335 $1,338 Operating income 74 52 93 63 282 Net Income 50 30 73 42 195
(Millions of Dollars) First Second Third Fourth Quarter Quarter Quarter Quarter Annual Total operating revenues $354 $311 $365 $315 $1,345 Operating income 79 59 90 57 285 Net Income 56 35 66 33 190
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
NONE PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
The directors listed below were elected April 24, 1997 to hold office until the next annual meeting of the Company's stockholders on April 23, 1998.
Name and Year First Became Director Age Principal Occupation; Directorships
Bill L. Amick 54 For more than five years, Chairman of the (1990) Board and Chief Executive Officer of Amick Farms, Inc., Batesburg, SC (vertically integrated broiler operation).
For more than five years, Chairman and Chief Executive Officer of Amick Processing, Inc. and Amick Broilers, Inc.
Director, SCANA Corporation, Columbia, SC.
James A. Bennett 37 Since December 1994, Senior Vice President (1997) and Director of Community Banking of First Citizens Bank, Columbia, SC.
From March 1991 to December 1994, President of Victory Savings Bank, Columbia, SC.
Director, SCANA Corporation
William B. Bookhart, Jr. 56 For more than five years, a partner in (1979) Bookhart Farms, Elloree, SC (general farming).
Director, SCANA Corporation, Columbia, SC.
William T. Cassels, Jr. 68 For more than five years, Chairman of the (1990) Board, Southeastern Freight Lines, Inc., Columbia, SC (trucking business).
Director, SCANA Corporation, Columbia, SC; Member, Advisory Board of Liberty Mutual Insurance Group.
Hugh M. Chapman 65 Since June 30, 1997, retired from (1988) NationsBank South, Atlanta, GA (a division of NationsBank Corporation, bank holding company).
For more than five years prior to June 30, 1997 Chairman of NationsBank South, Atlanta, GA
Director, SCANA Corporation, Columbia, SC; West Point-Stevens.
Name and Year First Became Director Age Principal Occupation; Directorships
Elaine T. Freeman 62 For more than five years, Executive Director (1992) of ETV Endowment of South Carolina, Inc. (non-profit organization), Spartanburg, SC.
Director, National Bank of South Carolina, Columbia, SC; SCANA Corporation, Columbia, SC.
Lawrence M. Gressette, Jr. 66 Since February 28, 1997, Chairman Emeritus (1987) of SCANA Corporation.
For more than five years prior to February 28, 1997, Chairman of the Board and Chief Executive Officer of SCANA Corporation and Chairman of the Board and Chief Executive Officer of all SCANA subsidiaries, including the Company.
For more than five years prior to December 13, 1995, President of SCANA Corporation.
Director, Wachovia Corporation, Winston- Salem, NC; Powertel, Inc., West Point, GA; SCANA Corporation, Columbia, SC.
W. Hayne Hipp 58 For more than five years, President and (1983) Chief Executive Officer, The Liberty Corporation, Greenville, SC (insurance and broadcasting holding company).
Director, The Liberty Corporation, Greenville, SC; Wachovia Corporation, Winston-Salem, NC; SCANA Corporation, Columbia, SC.
F. Creighton McMaster 68 For more than five years, President and (1974) Manager, Winnsboro Petroleum Company, Winnsboro, SC (wholesale distributor of petroleum products).
Director, First Union South Carolina, Greenville, SC; SCANA Corporation, Columbia, SC.
Lynne M. Miller 46 For more than five years, President of (1997) Environmental Strategies Corporation, Reston, VA (environmental consulting and engineering firm).
Director, SCANA Corporation, Columbia, SC.
John B. Rhodes 67 For more than five years, Chairman and (1967) Chief Executive Officer, Rhodes Oil Company, Inc., Walterboro, SC (distributor of petroleum products).
Director, SCANA Corporation, Columbia, SC.
Name and Year First Became Director Age Principal Occupation; Directorships
Maceo K. Sloan 48 For more than five years, Chairman, (1997) President and CEO of Sloan Financial Group, Inc. and Chairman, President and CEO of NCM Capital Management Group, Inc.
Director, SCANA Corporation, Columbia, SC.
William B. Timmerman 51 Since March 1, 1997, Chairman and Chief (1991) Executive Officer of SCANA Corporation.
From August 21, 1996 to March 1, 1997, Chief Operating Officer of SCANA Corporation.
Since December 13, 1995, President of SCANA Corporation.
From May 1, 1994 to December 13, 1995, Executive Vice President of SCANA Corporation.
Since August 25, 1993, Assistant Secretary of SCANA Corporation and all of its subsidiaries, including the Company.
From August 28, 1991 to February 20, 1996, Chief Financial Officer of the Company.
For more than five years prior to May 1, 1994, Senior Vice President of SCANA Corporation.
For more than five years prior to February 20, 1996, Controller of SCANA Corporation.
Director, SCANA Corporation, Columbia, SC; Powertel, Inc., West Point, GA, ITC^DeltaCom Board Member, West Point, GA. and Wachovia Bank, N. A., Columbia, S. C.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
All of the Company's common stock is held by its parent, SCANA Corporation. The required forms indicate that no equity securities of the Company are owned by its directors and executive officers. Based solely on a review of the copies of such forms and amendments furnished to the Company and written representations from the executive officers and directors, the Company believes that during 1997 all Section 16(a) filing requirements applicable to its executive officers, directors and greater than 10% beneficial owners were complied with.
ITEM 11. EXECUTIVE COMPENSATION
The following table contains information with respect to compensation paid or accrued during the years 1997, 1996 and 1995 to the Chief Executive Officer of the Company, to each of the other four most highly compensated executive officers of the Company during 1997, who were serving as executive officers of the Company at the end of 1997 and to L. M. Gressette, Jr., the Company's former Chief Executive Officer, who retired in February 1997.
Payouts will occur when SCANA's Total Shareholder Return ("TSR") is in the top two-thirds of a peer group of utilities, and will vary based on SCANA's ranking against the peer group. Executives earn threshold payouts at the 33rd percentile of three-year performance. Target payouts will be made at the 50th percentile of three-year performance. Maximum payouts will be made when the TSR is at or above the 75th percentile of the peer group. Payments will be made on a sliding scale for performance between threshold and target and target and maximum. No payouts will be earned if performance is at less than the 33rd percentile. Awards are denominated in shares of SCANA Common Stock and may be paid in either stock or cash or a combination of both.
DEFINED BENEFIT PLANS
In addition to the qualified Retirement Plan for all employees, SCANA has Supplemental Executive Retirement Plans ("SERPs") for certain eligible employees, including officers of its subsidiaries. A SERP is an unfunded plan which provides for benefit payments in addition to those payable under a qualified retirement plan. It maintains uniform application of the Retirement Plan benefit formula and would provide, among other benefits, payment of Retirement Plan formula pension benefits, if any, which exceed those payable under the Internal Revenue Code ("IRC") maximum benefit limitations.
The following table illustrates the estimated maximum annual benefits payable upon retirement at normal retirement date under the Retirement Plan and the SERPs.
Pension Plan Table
Final Service Years Average Pay 15 20 25 30 35
$150,000 $ 41,965 $ 55,953 $ 69,942 $ 83,930 $ 86,668 200,000 56,965 75,953 94,942 113,930 117,918 250,000 71,965 95,953 119,942 143,930 149,168 300,000 86,965 115,953 144,942 173,930 180,418 350,000 101,965 135,953 169,942 203,930 211,668 400,000 116,965 155,953 194,942 233,930 242,918 450,000 131,965 175,953 219,942 263,930 274,168
500,000 146,965 195,953 244,942 293,930 305,418
550,000 161,965 215,953 269,942 323,930 336,668 600,000 176,965 235,953 294,942 353,930 367,918 650,000 191,965 255,953 319,942 383,930 399,168 700,000 206,965 275,953 344,942 413,930 430,418 750,000 221,965 295,953 369,942 443,930 461,668
800,000 236,965 315,953 394,942 473,930 492,918
For all the executive officers named in the Summary Compensation Table for 1997, the compensation shown in the column labeled "Salary" of the Summary Compensation Table is covered by the Retirement Plan and/or a SERP. As of December 31, 1997, Messrs. Timmerman, Skolds, Bullwinkel, Marsh and Darby had credited service under the Retirement Plan (or its equivalent under the SERP) of 19, 11, 26, 13 and 29 years, respectively. Mr. Gressette currently is receiving a monthly benefit of $28,380 under the Retirement Plan and a SERP. Benefits are computed based on a straight-life annuity with an unreduced 60% surviving spouse benefit. The amounts in this table assume continuation of the primary Social Security benefits in effect at January 1, 1998, and are not subject to any deduction for Social Security or other offset amounts.
The Company also has a Key Employee Retention Plan (the "Key Employee Retention Plan") covering officers and certain other executive employees that provides supplemental retirement and/or death benefits for participants. Under the plan, each participant may elect to receive either (i) a monthly retirement benefit for 180 months upon retirement at or after age 65, equal to 25% of the average monthly salary of the participant over his final 36 months of employment prior to age 65, or (ii) an optional death benefit payable monthly to a participant's designated beneficiary for 180 months, in an amount equal to 35% of the average monthly salary of the participant over his final 36 months of employment prior to age 65. In the event of the participant's death prior to age 65, the Company will pay to the participant's designated beneficiary for 180 months, a monthly benefit equal to 50% of such participant's base monthly salary in effect at death.
All of the executive officers named in the Summary Compensation Table are participating in the plan. Mr. Gressette is receiving an annual benefit of $113,854 under the Key Employee Retention Plan. The estimated annual retirement benefits payable at age 65, based on projected eligible compensation (assuming increases of 4% per year) to the other persons named in the Summary Compensation Table are as follows: Mr. Timmerman-$170,199; Mr. Skolds-$135,858; Mr. Bullwinkel-$96,589 ; Mr. Marsh-$119,695 and Mr. Darby-$67,006.
TERMINATION, SEVERANCE AND CHANGE IN CONTROL ARRANGEMENTS
Since its approval by the Board on December 18, 1996, SCANA Corporation has maintained an Executive Benefit Plan Trust (the "Trust"). The purpose of the Trust and the related plans is to help retain and attract quality leadership in key company positions in the current transitional environment of the electric utility industry. The Trust is used to receive contributions which may be used to pay the deferred compensation benefits of certain directors, executives and other key employees of SCANA and its subsidiaries' in the event of a Change in Control (as defined in the Trust). All the executive officers named in the Summary Compensation Table participate in certain of the plans listed below (the "Plans") which are covered by the Trust.
(1) SCANA Corporation Voluntary Deferral Plan (2) SCANA Corporation Supplementary Voluntary Deferral Plan (3) SCANA Corporation Key Employee Retention Plan (4) SCANA Corporation Supplemental Executive Retirement Plan (5) SCANA Corporation Performance Share Plan (6) SCANA Corporation Annual Incentive Plan (7) SCANA Corporation Key Executive Severance Benefits Plan (8) SCANA Corporation Supplementary Key Executive Severance Benefits Plan
The Trust and the Plans provide flexibility to the Company in responding to a Potential Change in Control (as defined in the Trust) depending upon whether the Change in Control would be viewed as being "hostile" or "friendly". This flexibility includes the ability to deposit and withdraw Company contributions up to the point of a Change in Control, and to affect the number of plan participants who may be eligible for benefit distributions upon, or following, a Change in Control. The Plans listed above at items (7) and (8) cover all the named executive officers (except Mr. Gressette).
The Key Executive Severance Benefits Plan is operative as a "single trigger" plan, meaning that upon the occurrence of a "hostile" Change in Control, benefits provided under plans (1) through (6) above would be distributed in a lump sum. Under the terms of the Trust, in the event of a Change in Control that would trigger operation of the Key Executive Severance Benefits Plan, Mr. Gressette would receive immediate payout of all benefits under any of the Plans in which he is then participating.
In contrast, the Supplementary Key Executive Severance Benefits Plan (the "Supplementary Plan") is operative for a period of twenty-four months following a Change in Control which prior to its occurrence is viewed as being "friendly". In this circumstance, the Key Executive Severance Benefits Plan is inoperative. The Supplementary Plan is a "double trigger" plan that would pay benefits in lieu of those otherwise provided under plans (1) through (6) in either of two circumstances: (a) the participant's involuntary termination of employment without "Just Cause", or (b) the participant's voluntary termination of employment for "Good Reason" (as these terms are defined in the Supplementary Plan).
Benefit distributions relative to a Change in Control, as to which either the Key Executive Severance Benefits Plan or the Supplementary Plan is operative, will be grossed up to include estimated federal, state and local income taxes and any applicable excise taxes owed by Plan participants on those benefits, and paid in a lump sum. The benefit distributions would also be calculated so as to include, in addition to other benefits:
(a) Three times the sum of: (1) the officer's annual base salary in effect as of the Change in Control and (2) the larger of (i) the officer's full targeted annual incentive opportunity in effect as of the Change in Control under the Annual Incentive Plan, or (ii) the officer's average of actual annual incentive bonuses received during the prior three years under the Annual Incentive Plan; and
(b) an amount equal to the projected cost for coverage for three full years following the Change in Control as though the officer had continued to be a Company employee with respect to medical coverage, long-term disability coverage and either Life Plus (a special life insurance program combining whole life and term coverages) or group term life coverage in accordance with the officer's actual election, in each case so as to provide substantially the same level of coverage and benefits as the officer enjoyed as of the date of the Change in Control.
Benefit distributions pertaining to the Voluntary Deferral Plan would be calculated as of the date of the Change in Control inclusive of interest provided under the plan through such date, and benefits pertaining to the Supplementary Voluntary Deferral Plan would be calculated to include any implied dividends accruable under the plan through the date of the Change in Control.
Benefit distributions pertaining to the Key Employee Retention Plan would be calculated inclusive of projected increases to each participant's base salary using a fixed, market competitive rate as though the participant had reached the earlier of age 65 or completed 35 years of service.
Benefit distributions pertaining to the Supplemental Executive Retirement Plan would be calculated as an actuarial equivalent through the date of the Change in Control with three additional years of compensation at the participant's rate then in effect as though the participant had attained age 65 and completed 35 years of benefit service as of the date of the Change in Control and without any early retirement or other actuarial reductions, which benefit would then be reduced by the actuarial equivalent of the participant's qualified plan benefit amount under the Retirement Plan.
Benefit distributions pertaining to the Performance Share Plan would be equal to 100% of the targeted award as granted for all performance periods which are not yet completed as of the date of the Change in Control. Benefit distributions pertaining to the Annual Incentive Plan would be equal to 100% of the target award.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
During 1997, no officer, employee or former officer of SCANA or any of its subsidiaries served as a member of the Long-Term Compensation Committee or the Performance Committee, except Mr. Gressette who served as an ex-officio, non-voting member of the Performance Committee until his retirement in February 1997 and as a member of the Long-Term Compensation Committee following his retirement, and Mr. Timmerman who has been an ex-officio, non- voting member of the Performance Committee since March 1, 1997. Although Mr. Gressette and Mr. Timmerman served as members of the Performance Committee during 1997, neither participated in any of its decisions concerning executive officer compensation. As a member of the Long-Term Compensation Committee following his retirement, Mr. Gressette participated in the decisions regarding target awards made in 1997 under the Performance Share Plan.
Since January 1, 1997, SCANA and its subsidiaries including the Company have engaged in business transactions with entities with which Mr. Amick (a member of the Performance Committee and the Long-Term Compensation Committee), Mr. Chapman (Chairman of both the Performance Committee and the Long-Term Compensation Committee) and Mr. McMaster (a member of the Long-Term Compensation Committee) are related.
Mr. Amick is the owner of Team Amick Motor Sports, a business that owns and operates a NASCAR sanctioned racing car. This car participates in the Busch Grand National Racing Series. SCANA has entered into a shared sponsorship agreement with Team Amick Motor Sports pursuant to which SCANA will receive promotional considerations associated with NASCAR racing for an annual fee of $500,000.
Mr. Chapman was Chairman of NationsBank South, a division of NationsBank Corporation until his retirement on June 30, 1997. Since January 1, 1997, SCANA has engaged in various transactions in which affiliates of NationsBank Corporation acted as lender or provider of lines of credit or credit support to SCANA and its subsidiaries. The amount paid during 1997, by SCANA and its subsidiaries to NationsBank Corporation affiliates on account of such transactions was $361,870. In addition, during 1997, a NationsBank Corporation affiliate and a SCANA subsidiary have engaged in options and futures transactions and forward contracts relating to forecasted natural gas production. The amount paid during 1997, by a SCANA subsidiary to NationsBank Corporation affiliates on account of such transactions was $7,602,582. It is anticipated that similar transactions will continue in the future.
Mr. McMaster is the President and Manager of Winnsboro Petroleum Company. Purchases from Winnsboro Petroleum Company totaling $61,819 for petroleum products were made during 1997, by the Company and its subsidiaries. It is anticipated that similar transactions will continue.
Compensation of Directors
Fees. During 1997, directors who were not employees of the Company were paid $17,600 annually for services rendered as directors of SCANA and its subsidiaries, including the Company, $1,800 for each Board meeting attended and $850 for attendance at a committee meeting which is not held on the same day as a regular meeting of the Board. The fee for attendance at a telephone conference meeting is $200. The fee for attendance at a conference is $850. In addition, directors are paid, as part of their compensation, travel, lodging and incidental expenses related to attendance at meetings and conferences. The Board of Directors approved a plan effective January 1, 1997, whereby non-employee directors receive on a quarterly basis, 41% of their retainer in shares of SCANA common stock. The purpose of the plan is to promote the achievement of long-term objectives of SCANA by linking the personal interests of the non-employee directors to those of SCANA's shareholders by paying a portion of director compensation in stock. The Company believes this linkage will further promote the achievement of its long-term objectives.
Directors who are employees of SCANA or its subsidiaries receive no compensation for serving as directors or attending meetings.
In addition to regular director fees which he began to receive following his retirement, Mr. Gressette, as a Company retiree, received the retirement benefits described in the Summary Compensation Table on page 64.
Deferral Plan. SCANA has a plan (the "Voluntary Deferral Plan") pursuant to which directors may defer all or a portion of their fees paid to them in cash for services rendered and meeting attendance. Interest is earned on the deferred amounts at a rate set by the Management Development and Corporate Committee (the Performance Committee). Since January 1, 1997, the rate has been set at the announced prime rate of Wachovia Bank, N. A. Mr. Cassels and Mr. Rhodes were the only directors participating in the plan during 1997. Mr. Cassels became a participant in January 1994, and Mr. Rhodes in July 1987. Interest credited to their deferral accounts during 1997, was $8,609 and $27,228, respectively.
Endowment Plan. Upon election to a second term, each director becomes eligible to participate in the Directors' Endowment Plan, which provides for the Company to make a tax deductible, charitable contribution totaling $500,000 to institutions of higher education designated by the SCANA director. A portion is contributed upon retirement of the director and the remainder upon the director's death. The plan is funded in part through insurance on the lives of the directors. Designated in-state institutions of higher education must be approved by the Chief Executive Officer. Any out-of-state designation must be approved by the Performance Committee. The designated institutions are reviewed on an annual basis by the Chief Executive Officer to assure compliance with the intent of the program. The plan is intended to reinforce the commitment to quality higher education and is intended to enhance the ability to attract and retain qualified board members.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The table set forth below indicates the shares of SCANA's common stock beneficially owned as of March 10, 1998 by each director, each of the persons named in the Summary Compensation Table on page 64 (the "Named Executive Officer"), the directors and current executive officers of the Company as a group.
SECURITY OWNERSHIP OF MANAGEMENT
Name of Beneficial Amount and Nature Name of Beneficial Amount and Nature Owner of Ownership 1 Owner of Ownership 1 B. L. Amick 3,355 W. Hayne Hipp 3,145 J. A. Bennett 669 K. M. Marsh 9,760 W. B. Bookhart, Jr. 17,973 F. C. McMaster 5,975 G. J. Bullwinkel 20,167 L. M. Miller 1,281 W. T. Cassels, Jr. 2,355 J. B. Rhodes 9,052 H. M. Chapman 6,345 J. L. Skolds 9,473 W. A. Darby 23,336 M. K. Sloan 581 E. T. Freeman 4,675 W. B. Timmerman 28,567 L. M. Gressette, Jr. 59,352
All directors and executive officers as a group (17 persons) TOTAL 206,061. TOTAL PERCENT OF CLASS 0.2%
- ---------- 1 Includes shares owned by close relatives, the beneficial ownership of which is disclaimed by the director, nominee or Named Executive Officers, as follows:
Mr. Amick - 480; Mr. Bookhart - 5,029; Mr. Gressette - 1,060; and Mr. McMaster - 2,000; and by all directors, nominees and current executive officers - 8,569 in total.
Includes shares purchased through December 31, 1997, but not thereafter, by the Trustee under the Company's Stock Purchase- Savings Plan (the Savings Plan).
The information set forth above as to the security ownership of common stock has been furnished to the Company by such persons.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
For information regarding certain relationships and related transactions, see Item 11, "Compensation Committee Interlocks and Insider Participation."
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statements and Schedules
See Index to Consolidated Financial Statements and Supplementary Data on page 33.
Exhibits Filed
Exhibits required to be filed with this Annual Report on Form 10-K are listed in the Exhibit Index following the signature page. Certain of such exhibits which have heretofore been filed with the Securities and Exchange Commission and which are designated by reference to their exhibit number in prior filings are hereby incorporated herein by reference and made a part hereof.
As permitted under Item 601(b)(4)(iii), instruments defining the rights of holders of long-term debt of less than 10 percent of the total consolidated assets of the Company and its subsidiaries, have been omitted and the Company agrees to furnish a copy of such instruments to the Commission upon request.
Reports on Form 8-K
None
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.
(REGISTRANT) SOUTH CAROLINA ELECTRIC & GAS COMPANY
BY (SIGNATURE) s/J. L. Skolds (NAME AND TITLE) J. L. Skolds, President and Chief Operating Officer DATE February 17, 1998
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.
(i) Principal executive officer:
BY (SIGNATURE) s/W. B. Timmerman (NAME AND TITLE) W. B. Timmerman Chairman of the Board, Chief Executive Officer and Director DATE February 17, 1998
(ii) Principal financial officer:
BY (SIGNATURE) s/K. B. Marsh (NAME AND TITLE) K. B. Marsh, Chief Financial Officer DATE February 17, 1998
(iii) Principal accounting officer:
BY (SIGNATURE) s/J. E. Addison (NAME AND TITLE) J. E. Addison, Vice President and Controller DATE February 17, 1998
BY (SIGNATURE) s/B. L. Amick (NAME AND TITLE) B. L. Amick, Director DATE February 17, 1998
BY (SIGNATURE) s/J. A. Bennett (NAME AND TITLE) J. A. Bennett, Director DATE February 17, 1998
BY (SIGNATURE) s/W. B. Bookhart, Jr. (NAME AND TITLE) W. B. Bookhart, Jr., Director DATE February 17, 1998
BY (SIGNATURE) s/W. T. Cassels, Jr. (NAME AND TITLE) W. T. Cassels, Jr., Director DATE February 17, 1998
BY (SIGNATURE) s/H. M. Chapman (NAME AND TITLE) H. M. Chapman, Director DATE February 17, 1998
BY (SIGNATURE) s/E. T. Freeman (NAME AND TITLE) E. T. Freeman, Director DATE February 17, 1998
BY (SIGNATURE) s/L. M. Gressette, Jr. (NAME AND TITLE) L. M. Gressette, Jr., Director DATE February 17, 1998
BY (SIGNATURE) s/W. Hayne Hipp (NAME AND TITLE) W. Hayne Hipp, Director DATE February 17, 1998
BY (SIGNATURE) s/F. C. McMaster (NAME AND TITLE) F. C. McMaster, Director DATE February 17, 1998
BY (SIGNATURE) s/L. M. Miller (NAME AND TITLE) L. M. Miller, Director DATE February 17, 1998
BY (SIGNATURE) s/J. B. Rhodes (NAME AND TITLE) J. B. Rhodes, Director DATE February 17, 1998
BY (SIGNATURE) s/M. K. Sloan (NAME AND TITLE) M. K. Sloan, Director DATE February 17, 1998
SOUTH CAROLINA ELECTRIC & GAS COMPANY Sequentially EXHIBIT INDEX Numbered Number Pages 2. Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession Not Applicable
3. Articles of Incorporation and By-Laws
A. Restated Articles of Incorporation of the Company as adopted on December 15, 1993 (Exhibit 3-A to Form 10-Q for the quarter ended June 30, 1994, File No. 1-3375).................... # B. Articles of Amendment, dated June 7, 1994, filed June 9, 1994 (Exhibit 3-B to Form 10-Q for the quarter ended June 30, 1994, File No. 1-3375).... # C. Articles of Amendment, dated November 9, 1994 (Exhibit 3-C to Form 10-K for the year ended December 31, 1994, File No. 1-3375)...................... # D. Articles of Amendment, dated December 9, 1994 (Exhibit 3-D to Form 10-K for the year ended December 31, 1994, File No. 1-3375)...................... # E. Articles of Correction, dated January 17, 1995 (Exhibit 3-E to Form 10-K for the year ended December 31, 1994, File No. 1-3375)...................... # F. Articles of Amendment, dated January 13, 1995 and filed January 17, 1995 (Exhibit 3-F to Form 10-K for the year ended December 31, 1994, File No. 1-3375)......................................... # G. Articles of Amendment dated March 31, 1995 (Exhibit 3-G to Form 10-Q for the quarter ended March 31, 1995, File No. 1-3375)................... # H. Articles of Correction - Amendment to Statement filed March 31, 1995, dated December 13, 1995 (Exhibit 3-H to Form 10-K for the year ended December 31. 1995, File No. 1-3375)...................... # I. Articles of Amendment dated December 13, 1995 (Exhibit 3-I to Form 10-K for the year ended December 31, 1995, File No. 1-3375)...................... # J. Copy of By-Laws of the Company as revised and amended on December 17, 1997 (Filed herewith)............ 77 K. Articles of Amendment dated February 18, 1997 (Exhibit 3-L to Registration Statement No. 333-24919).... # L. Articles of Amendment dated February 21, 1997 (Exhibit 3-L to Form 10-Q for the quarter ended March 31, 1997).......................................... # M. Articles of Amendment dated April 22, 1997 (Exhibit 3-M to Form 10-Q for the quarter ended June 30, 1997)..................................... #
4. Instruments Defining the Rights of Security Holders, Including Indentures A. Indenture dated as of January 1, 1945, from the South Carolina Power Company (the "Power Company") to Central Hanover Bank and Trust Company, as Trustee, as supplemented by three Supplemental Indentures dated respectively as of May 1, 1946, May 1, 1947 and July 1, 1949 (Exhibit 2-B to Registration No. 2-26459)................................ # B. Fourth Supplemental Indenture dated as of April 1, 1950, to Indenture referred to in Exhibit 4A, pursuant to which the Company assumed said Indenture (Exhibit 2-C to Registration No. 2-26459)...... #
# Incorporated herein by reference as indicated.
SOUTH CAROLINA ELECTRIC & GAS COMPANY Exhibit Index (Continued) Sequentially Numbered Number Pages
4. (continued) C. Fifth through Fifty-second Supplemental Indentures to Indenture referred to in Exhibit 4A dated as of the dates indicated below and filed as exhibits to the Registration Statements and 1934 Act reports whose file numbers are set forth below..................................................... # December 1, 1950 Exhibit 2-D to Registration No. 2-26459 July 1, 1951 Exhibit 2-E to Registration No. 2-26459 June 1, 1953 Exhibit 2-F to Registration No. 2-26459 June 1, 1955 Exhibit 2-G to Registration No. 2-26459 November 1, 1957 Exhibit 2-H to Registration No. 2-26459 September 1, 1958 Exhibit 2-I to Registration No. 2-26459 September 1, 1960 Exhibit 2-J to Registration No. 2-26459 June 1, 1961 Exhibit 2-K to Registration No. 2-26459 December 1, 1965 Exhibit 2-L to Registration No. 2-26459 June 1, 1966 Exhibit 2-M to Registration No. 2-26459 June 1, 1967 Exhibit 2-N to Registration No. 2-29693 September 1, 1968 Exhibit 4-O to Registration No. 2-31569 June 1, 1969 Exhibit 4-C to Registration No. 33-38580 December 1, 1969 Exhibit 4-Q to Registration No. 2-35388 June 1, 1970 Exhibit 4-R to Registration No. 2-37363 March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324 January 1, 1972 Exhibit 4-C to Registration No. 33-38580 July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291 May 1, 1975 Exhibit 4-C to Registration No. 33-38580 July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908 February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304 December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936 March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662 May 1, 1977 Exhibit 4-C to Registration No. 33-38580 February 1, 1978 Exhibit 4-C to Registration No. 33-38580 June 1, 1978 Exhibit 2-A-3 to Registration No. 2-61653 April 1, 1979 Exhibit 4-C to Registration No. 33-38580 June 1, 1979 Exhibit 4-C to Registration No. 33-38580 April 1, 1980 Exhibit 4-C to Registration No. 33-38580 June 1, 1980 Exhibit 4-C to Registration No. 33-38580 December 1, 1980 Exhibit 4-C to Registration No. 33-38580 April 1, 1981 Exhibit 4-D to Registration No. 33-49421 June 1, 1981 Exhibit 4-D to Registration No. 2-73321 March 1, 1982 Exhibit 4-D to Registration No. 33-49421 April 15, 1982 Exhibit 4-D to Registration No. 33-49421 May 1, 1982 Exhibit 4-D to Registration No. 33-49421 December 1, 1984 Exhibit 4-D to Registration No. 33-49421 December 1, 1985 Exhibit 4-D to Registration No. 33-49421 June 1, 1986 Exhibit 4-D to Registration No. 33-49421 February 1, 1987 Exhibit 4-D to Registration No. 33-49421 September 1, 1987 Exhibit 4-D to Registration No. 33-49421 January 1, 1989 Exhibit 4-D to Registration No. 33-49421 January 1, 1991 Exhibit 4-D to Registration No. 33-49421 February 1, 1991 Exhibit 4-D to Registration No. 33-49421 July 15, 1991 Exhibit 4-D to Registration No. 33-49421 August 15, 1991 Exhibit 4-D to Registration No. 33-49421 April 1, 1993 Exhibit 4-E to Registration No. 33-49421 July 1, 1993 Exhibit 4-D to Registration No. 33-57955 D. Indenture dated as of April 1, 1993 from South Carolina Electric & Gas Company to NationsBank of Georgia, National Association (Filed as Exhibit 4-F to Registration Statement No. 33-49421)......................................... # E. First Supplemental Indenture to Indenture referred to in 4-D dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421)......................... #
# Incorporated herein by reference as indicated.
SOUTH CAROLINA ELECTRIC & GAS COMPANY EXHIBIT INDEX
Exhibit Index (Continued) Sequentially Numbered Number Pages F. Second Supplemental Indenture to Indenture referred to in 4-D dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955)......................... # G. Trust Agreement for SCE&G Trust I (Filed herewith).............. 93 H. Certificate of Trust for SCE&G Trust I (Filed herewith)......... 96 I. Form of Junior Subordinated Indenture for SCE&G Trust I (Filed herewith)................................................ 97 J. Form of Guarantee Agreement for SCE&G Trust I (Filed herewith)....................................................... 177 K. Form of Amended & Restated Trust Agreement for SCE&G Trust I (Filed herewith)........................................ 198
9. Voting Trust Agreement Not Applicable
10. Material Contracts A. Copy of Supplemental Executive Retirement Plan (Exhibit 10-A to Form 10-K for the year ended December 31, 1980)............................................ 276
11. Statement Re Computation of Per Share Earnings Not Applicable
12. Statement re Computation of Ratios (Filed herewith)................ 295
13. Annual Report to Security Holders, Form 10-Q or Quarterly Report to Security Holders Not Applicable
16. Letter Re Change in Certifying Accountant Not Applicable
18. Letter Re Change in Accounting Principles Not Applicable
21. Subsidiaries of the Registrant Not Applicable
22. Published Report Regarding Matters Submitted to Vote of Security Holders Not Applicable
23. Consents of Experts and Counsel Consent of Deloitte & Touche LLP................................... 299
24.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
Independent Auditors' Report....................................... 34
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1997 and 1996... 35
Consolidated Statements of Income and Retained Earnings for the years ended December 31, 1997, 1996 and 1995............. 37
Consolidated Statements of Cash Flows for the years ended December 31, 1997, 1996 and 1995............................. 38
Consolidated Statements of Capitalization as of December 31, 1997 and 1996................................... 39
Notes to Consolidated Financial Statements..................... 41
Supplemental financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the consolidated financial statements or in the notes thereto.
INDEPENDENT AUDITORS' REPORT
South Carolina Electric & Gas Company:
We have audited the accompanying Consolidated Balance Sheets and Statements of Capitalization of South Carolina Electric & Gas Company (Company) as of December 31, 1997 and 1996 and the related Consolidated Statements of Income and Retained Earnings and of Cash Flows for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1997 and 1996 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1997 in conformity with generally accepted accounting principles.
s/Deloitte & Touche LLP DELOITTE & TOUCHE LLP Columbia, South Carolina February 9, 1998
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:
A. Organization and Principles of Consolidation
The Company, a public utility, is a South Carolina corporation organized in 1924 and a wholly owned subsidiary of SCANA Corporation (SCANA), a South Carolina holding company. The Company is engaged predominately in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina.
The accompanying Consolidated Financial Statements include the accounts of the Company, South Carolina Fuel Company, Inc. (Fuel Company) and SCE&G Trust I. (See Note 1N.) Intercompany balances and transactions between the Company, Fuel Company and SCE&G Trust I have been eliminated in consolidation.
Affiliated Transactions
The Company has entered into agreements with certain affiliates to purchase gas for resale to its distribution customers and to purchase electric energy. The Company purchases all of its natural gas requirements from Pipeline Corporation and at December 31, 1997 and 1996 the Company had approximately $22.1 million and $22.3 million, respectively, payable to Pipeline Corporation for such gas purchases. The Company purchases all of the electric generation of Williams Station, which is owned by GENCO, under a unit power sales agreement. At December 31, 1997 and 1996 the Company had approximately $9.1 million and $8.6 million, respectively, payable to GENCO for unit power purchases. Such unit power purchases, which are included in "Purchased power," amounted to approximately $99.8 million, $95.3 million and $83.5 million in 1997, 1996 and 1995, respectively.
Total interest income, based on market interest rates, associated with the Company's advances to affiliated companies was approximately $20,000, $36,000 and $174,000 in 1997, 1996 and 1995, respectively.
In 1997 and 1996 there were no amounts relating to advances from affiliated companies included in "Other interest expense"; however, for 1995 $114,000 was included. Intercompany interest is calculated at market rates.
B. Basis of Accounting
The Company accounts for its regulated utility operations, assets and liabilities in accordance with the provisions of Statements of Financial Accounting Standards No. 71 (SFAS 71). The accounting standard requires cost-based rate-regulated utilities to recognize in their financial statements revenues and expenses in different time periods than do enterprises that are not rate-regulated. As a result the Company has recorded, as of December 31, 1997, approximately $236 million and $62 million of regulatory assets and liabilities, respectively, including amounts recorded for deferred income tax assets and liabilities of approximately $118 million and $52 million, respectively. The electric and gas regulatory assets of approximately $71 million and $44 million, respectively (excluding deferred income tax assets) are being recovered through rates and, as discussed in Note 2A, the Public Service Commission of South Carolina (PSC) has approved accelerated recovery of approximately $45 million of the electric regulatory assets. In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and would be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations in the period the write-off is recorded, but it is not expected that cash flows or financial position would be materially affected.
C. System of Accounts
The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and as adopted by the PSC.
D. Utility Plant
Utility plant is stated substantially at original cost. The costs of additions, renewals and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged, along with the cost of removal, less salvage, to accumulated depreciation. The costs of repairs, replacements and renewals of items of property determined to be less than a unit of property are charged to maintenance expense.
The Company, operator of the V. C. Summer Nuclear Station (Summer Station), and the South Carolina Public Service Authority (PSA) are joint owners of Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to the Company's portion of Summer Station was approximately $978.2 million and $937.2 million as of December 31, 1997 and 1996, respectively. Accumulated depreciation associated with the Company's share of Summer Station was approximately $323.6 million and $313.2 million as of December 31, 1997 and 1996, respectively. The Company's share of the direct expenses associated with operating Summer Station is included in "Other operation" and "Maintenance" expenses.
E. Allowance for Funds Used During Construction
AFC, a noncash item, reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company has calculated AFC using composite rates of 8.8%, 8.1% and 8.6% for 1997, 1996 and 1995, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process and sulfur dioxide emission allowances is capitalized at the actual interest amount.
F. Revenue Recognition
Customers' meters are read and bills are rendered on a monthly cycle basis. Base revenue is recorded during the accounting period in which the meters are read.
Fuel costs for electric generation are collected through the fuel cost component in retail electric rates. The fuel cost component contained in electric rates is established by the PSC during annual fuel cost hearings. Any difference between actual fuel costs and that contained in the fuel cost component is deferred and included when determining the fuel cost component during the next annual fuel cost hearing. The Company had undercollected through the electric fuel cost component approximately $1.3 million and at December 31, 1997 and overcollected approximately $ 1.9 million December 31, 1996 which are included in "Deferred Debits - Other" and "Deferred Credits - Other," respectively.
Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the PSC during annual gas cost recovery hearings. Any difference between actual gas cost and that contained in the rates is deferred and included when establishing gas costs during the next annual gas cost recovery hearing. At December 31, 1997 and 1996 the Company had undercollected through the gas cost recovery procedure approximately $7.6 million and $10.9 million, respectively, which are included in "Deferred Debits - Other."
The Company's gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment, which minimizes fluctuations in gas revenues due to abnormal weather conditions.
G. Depreciation and Amortization Provisions for depreciation are recorded using the straight- line method for financial reporting purposes and are based on the estimated service lives of the various classes of property. The composite weighted average depreciation rates were 3.09%, 3.13% and 3.02% for 1997, 1996 and 1995, respectively.
Nuclear fuel amortization, which is included in "Fuel used in electric generation" and is recovered through the fuel cost component of the Company's rates, is recorded using the units-of- production method. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the Department Of Energy (DOE) under a contract for disposal of spent nuclear fuel.
The acquisition adjustment relating to the purchase of certain gas properties in 1982 is being amortized over a 40-year period using the straight-line method.
H. Nuclear Decommissioning
Decommissioning of Summer Station is presently scheduled to commence when the operating license expires in the year 2022. Based on a 1991 study, the expenditures (on a before-tax basis) related to the Company's share of decommissioning activities are estimated, in 2022 dollars assuming a 4.5% annual rate of inflation, to be $545.3 million including partial reclamation costs. The Company is providing for its share of estimated decommissioning costs of Summer Station over the life of Summer Station. The Company's method of funding decommissioning cost is referred to as COMReP (Cost of Money Reduction Plan). Under this plan, funds collected through rates ($3.2 million in 1997 and 1996) are used to pay premiums on insurance policies on the lives of certain Company personnel. The Company is the beneficiary of these policies. Through these insurance contracts, the Company is able to take advantage of income tax benefits and accrue earnings on the fund on a tax-deferred basis at a rate higher than can be achieved using more traditional funding approaches. Amounts for decommissioning collected through electric rates, insurance proceeds, and interest on proceeds less expenses are transferred by the Company to an external trust fund in compliance with the financial assurance requirements of the Nuclear Regulatory Commission. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis. The trust's sources of decommissioning funds under the COMReP program include investment components of life insurance policy proceeds, return on investment and the cash transfers from the Company described above. The Company records its liability for decommissioning costs in deferred credits.
Pursuant to the National Energy Policy Act passed by Congress in 1992 and the requirements of the DOE, the Company has recorded a liability for its estimated share of the DOE's decontamination and decommissioning obligation. The liability, approximately $4.0 million at December 31, 1997, has been included in "Long-Term Debt, Net." The Company is recovering the cost associated with this liability through the fuel cost component of its rates; accordingly, this amount has been deferred and is included in "Deferred Debits - Other."
I. Income Taxes
Deferred tax assets and liabilities are recorded for the tax effects of temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense.
J. Pension Expense
The Company participates in SCANA's noncontributory defined benefit pension plan, which covers all permanent employees. Benefits are based on years of accredited service and the employee's average annual base earnings received during the last three years of employment. SCANA's policy has been to fund the plan to the extent permitted by the applicable Federal income tax regulations as determined by an independent actuary.
Net periodic pension cost for the years ended December 31, 1997, 1996 and 1995 included the following components:
1997 1996 1995 (Millions of Dollars) Service cost--benefits earned during the period $ 6.8 $ 6.5 $ 5.2 Interest cost on projected benefit obligation 23.5 22.0 19.5 Adjustments: Return on plan assets (119.5) (78.6) (103.9) Net amortization and deferral 72.8 40.1 74.8 Amounts contributed by the Company's affiliates (0.6) (0.3) (0.2) Net periodic pension (income) expense $(17.0) $(10.3) $ (4.6)
The determination of net periodic pension cost is based upon the following assumptions:
1997 1996 1995 Annual discount rate 7.5% 7.5% 8.0% Expected long-term rate of return on plan assets 8.0% 8.0% 8.0% Annual rate of salary increases 3.0% 3.0% 2.5%
The following table sets forth the funded status of the plan at December 31, 1997 and 1996:
1997 1996 (Millions of Dollars) Actuarial present value of benefit obligations: Vested benefit obligation $259.7 $243.9 Nonvested benefit obligation 25.4 23.7 Accumulated benefit obligation $285.1 $267.6
Plan assets at fair value (invested primarily in equity and debt securities) $632.9 $523.5 Projected benefit obligation 344.4 306.9 Plan assets greater than projected benefit obligation 288.5 216.6 Unrecognized net transition liability 7.4 8.2 Unrecognized prior service costs 13.4 8.2 Unrecognized net gain (227.1) (175.1) Pension asset recognized in Consolidated Balance Sheets $ 82.2 $ 57.9
The accumulated benefit obligation is based on the plan's benefit formulas without considering expected future salary increases. The following table sets forth the assumptions used in determining the amounts shown above for the years 1997 and 1996.
1997 1996
Annual discount rate used to determine benefit obligations 7.5% 7.5% Assumed annual rate of future salary increases for projected benefit obligation 4.0% 3.0%
In addition to pension benefits, the Company provides certain health care and life insurance benefits to active and retired employees. The costs of postretirement benefits other than pensions are accrued during the years the employees render the service necessary to be eligible for the applicable benefits. The Company expensed approximately $8.1 million, $9.8 million and $8.5 million, net of payments to current retirees, for the years ended December 31, 1997, 1996 and 1995, respectively. Additionally, to accelerate the amortization of the remaining transition obligation for postretirement benefits other than pensions, as authorized by the PSC, the Company expensed approximately $15.6 million and $6.2 million for the years ended December 31, 1997 and 1996, respectively. (See Note 2A.)
Net periodic postretirement benefit cost for the years ended December 31, 1997, 1996 and 1995, included the following components:
1997 1996 1995 (Millions of Dollars)
Service cost--benefits earned during the period $ 2.5 $ 2.6 $ 2.1 Interest cost on accumulated postretirement benefit obligation 7.8 7.8 7.2 Adjustments: Return on plan assets - - - Amortization of unrecognized transition obligation 18.9 9.5 3.3 Other net amortization and deferral 0.8 1.2 0.7 Amounts contributed by the Company's affiliates (1.1) (0.7) (0.6) Net periodic postretirement benefit cost $28.9 $20.4 $12.7
The determination of net periodic postretirement benefit cost is based upon the following assumptions:
1997 1996 1995
Annual discount rate 7.5% 7.5% 8.0% Health care cost trend rate 9.0% 9.5% 11.0% Ultimate health care cost trend rate (to be achieved in 2004) 5.5% 5.5% 6.0%
The following table sets forth the funded status of the plan at December 31, 1997 and 1996:
1997 1996 (Millions of Dollars)
Accumulated postretirement benefit obligations for: Retirees $ 76.7 $ 74.2 Other fully eligible participants 5.9 6.6 Other active participants 26.2 29.3 Accumulated postretirement benefit obligation 108.8 110.1
Plan assets at fair value - - Accumulated postretirement benefit obligation 108.8 110.1 Plan assets less than accumulated postretirement benefit obligation (108.8) (110.1) Unrecognized net transition liability 29.8 48.7 Unrecognized prior service costs 5.8 6.2 Unrecognized net loss 12.2 17.8 Postretirement benefit liability recognized in Consolidated Balance Sheets $ (61.0) $ (37.4)
The accumulated postretirement benefit obligation is based upon the plan's benefit provisions and the following assumptions:
1997 1996 Assumed health care cost trend rate used to measure expected costs 9.0% 9.5% Ultimate health care cost trend rate (to be achieved in 2004) 5.5% 5.5% Annual discount rate 7.5% 7.5% Annual rate of salary increases 4.0% 3.0%
The effect of a one percentage-point increase in the assumed health care cost trend rate for each future year on the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year ended December 31, 1997 and the accumulated postretirement benefit obligation as of December 31, 1997 would be to increase such amounts by $0.2 million and $3.2 million, respectively.
K. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
For regulatory purposes, long-term debt premium, discount and expense are being amortized as components of "Interest on long-term debt, net" over the terms of the respective debt issues. Gains or losses on reacquired debt that is refinanced are deferred and amortized over the term of the replacement debt.
L. Environmental
The Company has an environmental assessment program to identify and assess current and former operating sites that could require environmental cleanup. As site assessments are initiated an estimate is made of the amount of expenditures, if any, necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated, accrued and actually expended to date for site assessments and cleanup relate primarily to regulated operations; such amounts are deferred and are being amortized and recovered through rates over a five-year period for electric operations and an eight-year period for gas operations. The Company has also recovered portions of its environmental liabilities through settlements with various insurance carriers. Deferred amounts, net of amounts recovered through rates and insurance settlements, totaled $32.4 million and $41.4 million at December 31, 1997 and 1996, respectively. The deferral includes the estimated costs to be associated with the matters discussed in Note 10C.
M. Fuel Inventories
Nuclear fuel and fossil fuel inventories and sulfur dioxide emission allowances are purchased and financed by Fuel Company under a contract which requires the Company to reimburse Fuel Company for all costs and expenses relating to the ownership and financing of fuel inventories and sulfur dioxide emission allowances. Accordingly, such fuel inventories and emission allowances and fuel-related assets and liabilities are included in the Company's consolidated financial statements. (See Note 4.)
N. Temporary Cash Investments
The Company considers temporary cash investments having original maturities of three months or less to be cash equivalents. Temporary cash investments are generally in the form of commercial paper, certificates of deposit and repurchase agreements. O. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the 1997 presentation.
P. Use of Estimates
The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates.
2. RATE MATTERS:
A. On January 9, 1996 the PSC issued an order granting the Company an increase in retail electric rates of 7.34%, which was designed to produce additional revenues, based on a test year, of approximately $67.5 million annually. The increase has been implemented in two phases. The first phase, an increase in revenues of approximately $59.5 million annually or 6.47%, commenced in January 1996. The second phase, an increase in revenues of approximately $8.0 million annually, or .87%, was implemented in January 1997. The PSC authorized a return on common equity of 12.0%. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million to be collected through rates over a ten-year period. Additionally, the PSC approved accelerated recovery of a significant portion of the Company's electric regulatory assets (excluding deferred income tax assets) and the remaining transition obligation for postretirement benefits other than pensions, changing the amortization periods to allow recovery by the end of the year 2000. The Company's request to shift, for ratemaking purposes, approximately $257 million of depreciation reserves from transmission and distribution assets to nuclear production assets was also approved. The Consumer Advocate appealed certain issues in the order to the South Carolina Circuit Court, which affirmed the PSC's decisions, and subsequently to the South Carolina Supreme Court which is expected to hear the case and issue a ruling prior to the end of 1998. While the outcome of this proceeding is uncertain, the Company does not believe that any significant adverse changes in the rate order is likely. The PSC's order does not apply to wholesale electric revenues under the FERC's jurisdiction, which constitute approximately two percent of the Company's electric revenues. The FERC rejected the transfer of depreciation reserves for rates subject to its jurisdiction.
B. In 1994 the PSC issued an order approving the Company's request to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former manufactured gas plants. The billing surcharge is subject to annual review and provides for the recovery of substantially all actual and projected site assessment and cleanup costs and environmental claims settlements for the Company's gas operations that had previously been deferred. In October 1997, as a result of the annual review, the PSC approved the Company's request to increase the billing surcharge from $.006 per therm to $.011 per therm which should enable the Company to recover the remaining balance of $29.6 million by December 2002.
C. In September 1992 the PSC issued an order granting the Company a $.25 increase in transit fares from $.50 to $.75 in both Columbia and Charleston, South Carolina; however, the PSC also required $.40 fares for low income customers and denied the Company's request to reduce the number of routes and frequency of service. The new rates were placed into effect in October 1992. The Company appealed the PSC's order to the Circuit Court, which in May 1995 ordered the case back to the PSC for reconsideration of several issues including the low income rider program, routing changes, and the $.75 fare. The Supreme Court declined to review an appeal of the Circuit Court decision and dismissed the case. The PSC and other intervenors filed another Petition for Reconsideration, which the Supreme Court denied. The PSC and other intervenors filed another appeal to the Circuit Court which the Circuit Court denied in an order dated May 9, 1996. In this order, the Circuit Court upheld its previous orders and remanded them to the PSC. During August 1996, the PSC heard oral arguments on the orders on remand from the Circuit Court. On September 30, 1996, the PSC issued an order affirming its previous orders and denied the Company's request for reconsideration. The Company has appealed these two PSC orders to the Circuit Court where they are awaiting action.
3. LONG-TERM DEBT:
The annual amounts of long-term debt maturities, including amounts due under nuclear and fossil fuel agreements (see Note 4), and sinking fund requirements for the years 1998 through 2002 are summarized as follows: Year Amount Year Amount (Millions of Dollars)
1998 $ 47.7 2001 $ 21.3 1999 27.8 2002 51.3 2000 201.5
Approximately $17.2 million of the portion of long-term debt payable in 1998 may be satisfied by either deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits, or by deposit of cash with the Trustee.
On August 7, 1996 the City of Charleston executed 30-year electric and gas franchise agreements with the Company. In consideration for the electric franchise agreement, the Company is paying the City $25 million over seven years (1996 through 2002) and has donated to the City the existing transit assets in Charleston. The $25 million is included in electric plant-in- service. In settlement of environmental claims the City may have had against the Company involving the Calhoun Park area, where the Company and its predecessor companies operated a manufactured gas plant until the 1960's, the Company is paying the City $26 million over a four-year period (1996 through 1999). Such amount is deferred (see Note 1L). The unpaid balances of these amounts are included in "Long-Term Debt."
The Company has three-year revolving lines of credit totaling $75 million, in addition to other lines of credit, that provide liquidity for issuance of commercial paper. The three- year lines of credit provide back-up liquidity when commercial paper outstanding is in excess of $175 million. The long-term nature of the lines of credit allow commercial paper in excess of $175 million to be classified as long-term debt. The Company had outstanding commercial paper of $13.3 million and $90 million at December 31, 1997 and 1996, at weighted average interest rates of 5.90% and 5.53%, respectively.
Substantially all utility plant and fuel inventories are pledged as collateral in connection with long-term debt.
4. FUEL FINANCINGS:
Nuclear and fossil fuel inventories and sulfur dioxide emission allowances are financed through the issuance by Fuel Company of short-term commercial paper. These short-term borrowings are supported by an irrevocable revolving credit agreement which expires December 19, 2000. Accordingly, the amounts outstanding have been included in long-term debt. The credit agreement provides for a maximum amount of $125 million that may be outstanding at any time.
Commercial paper outstanding totaled $80.3 million and $66.1 million at December 31, 1997 and 1996 at weighted average interest rates of 5.87% and 5.62%, respectively.
5. COMMON EQUITY:
The changes in "Stockholders' Investment" (Including Preferred Stock Not Subject to Purchase or Sinking Funds) during 1997, 1996 and 1995 are summarized as follows:
Common Preferred Millions Shares Shares of Dollars Balance December 31, 1994 40,296,147 322,877 $1,159.5 Changes in Retained Earnings: Net Income 169.2 Cash Dividends Declared: Preferred Stock (at stated rates) (5.7) Common Stock (121.4) Equity Contributions from Parent 139.5 Balance December 31, 1995 40,296,147 322,877 1,341.1 Changes in Retained Earnings: Net Income 190.5 Cash Dividends Declared: Preferred Stock (at stated rates) (5.4) Common Stock (135.8) Equity Contributions from Parent including transfer of assets 49.1 Balance December 31, 1996 40,296,147 322,877 1,439.5 Changes in Retained Earnings: Net Income 194.6 Cash Dividends Declared: Preferred Stock (at stated rates) (9.3) Common Stock (162.6) Equity Contributions from Parent 12.1 Issuance of Preferred Stock 1,000,000 100.0 Redemption of Preferred Stock (197,668) (19.8) Changes in Capital Stock Expense 0.1 Changes in Loss on Resale of Reacquired Stock (1.6) Balance December 31, 1997 40,296,147 1,125,209 $1,553.0
The Restated Articles of Incorporation of the Company and the Indenture underlying its First and Refunding Mortgage Bonds contain provisions that under certain circumstances could limit the payment of cash dividends on common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of the earnings therefrom. At December 31, 1997 approximately $21.5 million of retained earnings were restricted by this requirement as to payment of cash dividends on common stock.
6. PREFERRED STOCK:
The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. Retirements under sinking fund requirements are at par values.
The aggregate annual amount of purchase fund or sinking fund requirements for preferred stock for the years 1998 through 2002 is $0.6 million.
The changes in "Total Preferred Stock (Subject to Purchase or Sinking Funds)" during 1997, 1996 and 1995 are summarized as follows:
Number Millions of Shares of Dollars
Balance December 31, 1994 822,094 $ 51.9 Shares Redeemed: $100 par value (6,809) (0.7) $50 par value (51,666) (2.5) Balance December 31, 1995 763,619 48.7 Shares Redeemed: $100 par value (7,198) (0.7) $50 par value (50,319) (2.6) Balance December 31, 1996 706,102 45.4 Shares Redeemed: $100 par value (202,812) (20.3) $50 par value (252,196) (12.6) Balance December 31, 1997 251,094 $ 12.5
On October 28, 1997 SCE&G Trust I (the "Trust"), a wholly- owned subsidiary of the Company, issued $50 million (2,000,000 shares) of 7.55% Trust Preferred Securities, Series A (the "Preferred Securities"). The Company owns all of the Common Securities of the Trust (the "Common Securities"). The Preferred Securities and the Common Securities (the "Trust Securities") represent undivided beneficial ownership interests in the assets of the Trust. The Trust exists for the sole purpose of issuing the Trust Securities and using the proceeds thereof to purchase from the Company its 7.55% Junior Subordinated Debentures due September 30, 2027. The sole asset of the Trust is $50 million of Junior Subordinated Debentures of the Company. Accordingly, no financial statements of the Trust are presented. The Company's obligations under the Guarantee Agreement entered into in connection with the Preferred Securities, when taken together with the Company's obligation to make interest and other payments on the Junior Subordinated Debentures issued to the Trust and the Company's obligations under its Indenture pursuant to which the Junior Subordinated Debentures are issued, provides a full and unconditional guarantee by the Company of the Trust's obligations under the Preferred Securities. Proceeds were used to redeem preferred stock of the Company.
The preferred securities of the Trust are redeemable only in conjunction with the redemption of the related 7.55% Junior Subordinated Debentures. The Junior Subordinated Debentures will mature on September 30, 2027 and may be redeemed, in whole or in part, at any time on or after September 30, 2002 or upon the occurrence of a Tax Event. A Tax Event occurs if an opinion is received from counsel experienced in such matters that there is more than an insubstantial risk that: (1) the Trust is or will be subject to Federal income tax, with respect to income received or accrued on the Junior Subordinated Debentures, (2) interest payable by the Company on the Junior Subordinated Debentures will not be deductible, in whole or in part, by the Company for Federal income tax purposes, and (3) the Trust will be subject to more than a de minimis amount of other taxes, duties, or other governmental charges.
Upon the redemption of the Junior Subordinated Debentures, payment will simultaneously be applied to redeem Preferred Securities having an aggregate liquidation amount equal to the aggregate principal amount of the Junior Subordinated Debentures. The Preferred Securities are redeemable at $25 per preferred security plus accrued distributions.
7. INCOME TAXES:
Total income tax expense for 1997, 1996 and 1995 is as follows:
1997 1996 1995 (Millions of Dollars) Current taxes: Federal $ 88.0 $ 88.2 $ 94.1 State (6.9) 13.1 14.3 Total current taxes 81.1 101.3 108.4 Deferred taxes, net: Federal 3.7 8.3 (7.3) State 1.5 1.8 (0.6) Total deferred taxes 5.2 10.1 (7.9) Investment tax credits: Deferred - State 19.0 - - Amortization of amounts deferred-State (1.5) - - Amortization of amounts deferred-Federal (3.2) (3.2) (3.2) Total Investment Tax credit 14.3 (3.2) (3.2) Total income tax expense $100.6 $108.2 $ 97.3
The difference in total income tax expense and the amount calculated from the application of the statutory Federal income tax rate (35% for 1997, 1996 and 1995) to pre-tax income is reconciled as follows:
1997 1996 1995 (Millions of Dollars)
Net income $194.7 $190.5 $169.2 Total income tax expense: Charged to operating expenses 98.1 107.7 97.0 Charged (credited) to other items 2.5 0.5 0.3 Total pre-tax income $295.3 $298.7 $266.5
Income taxes on above at statutory Federal income tax rate $103.4 $104.5 $ 93.3 Increases (decreases) attributable to: State income taxes (less Federal income tax effect) 7.9 9.7 8.9 Deferred income tax reversal at higher than statutory rates (3.5) (3.4) (3.3) Amortization of Federal investment tax credits (3.2) (3.2) (3.2) Allowance for equity funds used during construction (2.1) (1.4) (3.3) Other differences, net (1.9) 2.0 4.9 Total income tax expense $100.6 $108.2 $ 97.3
The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $518.5 million at December 31, 1997 and $501.7 million at December 31, 1996 are as follows:
1997 1996 (Millions of Dollars) Deferred tax assets: Unamortized investment tax credits $ 55.4 $ 46.5 Cycle billing 20.5 19.8 Nuclear operations expenses 3.1 4.7 Deferred compensation 6.7 6.6 Other postretirement benefits 14.6 10.8 Other 8.1 6.6 Total deferred tax assets 108.4 95.0 Deferred tax liabilities: Property plant and equipment 561.2 540.9 Pension expense 27.5 21.8 Reacquired debt 7.5 8.3 Research and experimentation 19.5 12.5 Deferred fuel 3.6 3.7 Other 7.6 9.5 Total deferred tax liabilities 626.9 596.7 Net deferred tax liability $518.5 $501.7
The Internal Revenue Service has examined and closed consolidated Federal income tax returns of SCANA Corporation through 1989, and has examined and proposed adjustments to SCANA's Federal returns for 1990 through 1995. The Company does not anticipate that any adjustments which might result from these examinations will have a significant impact on the results of operations, cash flows or financial position of the Company.
8. FINANCIAL INSTRUMENTS:
The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 1997 and 1996 are as follows:
The information presented herein is based on pertinent information available to the Company as of December 31, 1997 and 1996. Although the Company is not aware of any factors that would significantly affect the estimated fair value amounts, such financial instruments have not been comprehensively revalued since December 31, 1997, and the current estimated fair value may differ significantly from the estimated fair value at that date.
The following methods and assumptions were used to estimate the fair value of the above classes of financial instruments:
Cash and temporary cash investments, including commercial paper, repurchase agreements, treasury bills and notes, are valued at their carrying amount.
Fair values of investments and long-term debt are based on quoted market prices of the instruments or similar instruments, or for those instruments for which there are no quoted market prices available, fair values are based on net present value calculations. Investments which are not considered to be financial instruments have been excluded from the carrying amount and estimated fair value. Settlement of long term debt may not be possible or may not be a prudent management decision.
Short-term borrowings are valued at their carrying amount.
The fair value of preferred stock (subject to purchase or sinking funds) is estimated on the basis of market prices.
Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been taken into consideration.
9. SHORT-TERM BORROWINGS:
The Company pays fees to banks as compensation for its committed lines of credit. Commercial paper borrowings are for 270 days or less. Details of lines of credit (including uncommitted lines of credit) and short-term borrowings, excluding amounts classified as long-term (Notes 3 and 4), at December 31, 1997 and 1996 and for the years then ended are as follows:
1997 1996 (Millions of dollars)
Authorized lines of credit at year-end $315 $145.0 Unused lines of credit at year-end $315 $145.0 Short-term borrowings outstanding at year-end: Commercial paper $13.3 $ 90.0 Weighted average interest rate 5.90% 5.53%
10. COMMITMENTS AND CONTINGENCIES:
A. Construction
SCANA and Westvaco Corporation have formed a limited liability company, Cogen South LLC, to build and operate a $170 million cogeneration facility at Westvaco's Kraft Division Paper Mill in North Charleston, South Carolina. SCANA and Westvaco each own a 50% interest in LLC. The facility will provide industrial process steam for the Westvaco paper mill and shaft horsepower to enable the Company to generate up to 99 megawatts of electricity. In addition to the cogeneration LLC, Westvaco has entered into a 20-year contract with the Company for all its electricity requirements at the North Charleston mill at the Company's standard industrial rate. Construction of the plant began in September 1996 and it is expected to be operational in the fall of 1998.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with public liability for a nuclear incident, currently establishes the liability limit for third-party claims associated with any nuclear incident at $8.9 billion. Each reactor licensee is currently liable for up to $79.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $10 million of the liability per reactor would be assessed per year. The Company's maximum assessment, based on its two-thirds ownership of Summer Station, would be approximately $52.9 million per incident, but not more than $6.7 million per year.
The Company currently maintains policies (for itself and on behalf of the PSA) with Nuclear Electric Insurance Limited (NEIL) and American Nuclear Insurers (ANI) providing combined property and decontamination insurance coverage of $2.0 billion for any losses at Summer Station. The Company pays annual premiums and, in addition, could be assessed a retroactive premium not to exceed five times its annual premium in the event of property damage loss to any nuclear generating facilities covered under the NEIL program. Based on the current annual premium, this retroactive premium would not exceed $5.1 million.
To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that the Company's rates would not recover the cost of any purchased replacement power, the Company will retain the risk of loss as a self-insurer. The Company has no reason to anticipate a serious nuclear incident at Summer Station. If such an incident were to occur, it could have a material adverse impact on the Company's results of operations, cash flows and financial position.
C. Environmental
In September 1992, the EPA notified the Company, the City of Charleston and the Charleston Housing Authority of their potential liability for the investigation and cleanup of the Calhoun Park area site in Charleston, South Carolina. This site encompasses approximately 30 acres and includes properties which were locations for industrial operations, including a wood preserving (creosote) plant, one of the Company's decommissioned manufactured gas plants, properties owned by the National Park Service and the City of Charleston and private properties. The site has not been placed on the National Priorities List, but may be added before cleanup is initiated. The PRPs have agreed with the EPA to participate in an
innovative approach to site investigation and cleanup called "Superfund Accelerated Cleanup Model," allowing the pre-cleanup site investigation process to be compressed significantly. The PRPs have negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study and a corresponding Scope of Work. Field work began in November 1993 and the EPA conditionally approved a Remedial Investigation Report in March 1997. Although the Company is continuing to investigate cost-effective clean-up methodologies, further work is pending EPA approval of the final draft of the Remedial Investigation Report. See Note 1L.
In October 1996 the City of Charleston and the Company settled all environmental claims the City may have had against the Company involving the Calhoun Park area for a payment of $26 million over four years (1996 through 1999) by the Company to the City. The Company is recovering the amount of the settlement, which does not encompass site assessment and cleanup costs, through rates in the same manner as other amounts accrued for site assessments and cleanup as discussed above. See Note 1L. As part of the environmental settlement, the Company has agreed to construct an 1,100 space parking garage on the Calhoun Park site and to transfer the facility to the City in exchange for a 20-year municipal bond backed by revenues from the parking garage and a mortgage on the parking garage. Construction is expected to begin in 1998. The total amount of the bond is not to exceed $16.9 million, the maximum expected project cost.
The Company owns three other decommissioned manufactured gas plant sites which contain residues of by-product chemicals. The Company is investigating the sites to monitor the nature and extent of the residual contamination.
D. Franchise Agreements
See Note 3 for a discussion of an electric franchise agreement between the Company and the City of Charleston.
E. Claims and Litigation
The Company is engaged in various claims and litigation incidental to its business operations which management anticipates will be resolved without material loss to the Company. No estimate of the range of loss from these matters can currently be determined.
11. SEGMENT OF BUSINESS INFORMATION:
Segment information at December 31, 1997, 1996 and 1995 and for the years then ended is as follows:
Electric Gas Transit Total (Millions of Dollars) Operating revenues $1,103 $234 $ 1 $1,338 Operating expenses, excluding depreciation and amortization 710 201 5 916 Depreciation and amortization 129 11 - 140 Total operating expenses 839 212 5 1,056 Operating income (loss) $ 264 $ 22 $(4) 282
Add - Other income, net 9 Less - Interest charges, net 95 Less - Preferred Dividend Requirements, including the Company - Obligated Mandatorily Redeemable Preferred Securities 10 Net income $ 186
Capital expenditures: Identifiable $218 $ 15 $ - $ 233
Utilized for overall Company operations 32 Total $ 265
Identifiable assets at December 31, 1997: Utility plant, net $2,951 $221 $ 2 $3,174 Inventories 69 2 - 71 Total $3,020 $223 $ - 3,245
Other assets 809 Total assets $4,054
Electric Gas Transit Total (Millions of Dollars) Operating revenues $1,107 $ 235 $ 3 $1,345 Operating expenses, excluding depreciation and amortization 711 204 9 924 Depreciation and amortization 123 12 - 135 Total operating expenses 834 216 9 1,059 Operating income (loss) $ 273 $ 19 $(6) 286
Add - Other income, net 4 Less - Interest charges, net 9 Less - Preferred stock dividends 6 Net income $ 185
Capital expenditures: Identifiable $ 197 $ 19 $ - $ 216
Utilized for overall Company operations 24 Total 240
Identifiable assets at December 31, 1996: Utility plant, net $2,870 $ 217 $ 2 $3,089 Inventories 76 2 - 78 Total $2,946 $ 219 $ 2 3,167
Other assets 792 Total assets $3,959
Electric Gas Transit Total (Thousands of Dollars) Operating revenues $1,006 $ 201 $ 4 $1,211 Operating expenses, excluding depreciation and amortization 657 170 10 837 Depreciation and amortization 104 13 1 118 Total operating expenses 761 183 11 955 Operating income (loss) $ 245 $ 18 $(7) 256
Add - Other income, net 9 Less - Interest charges, net 96 Less - Preferred stock dividends 6 Net income $ 163
Capital expenditures: Identifiable $ 245 $ 20 $ - $ 265
Utilized for overall Company operations 28 Total $ 293
Identifiable assets at December 31, 1995: Utility plant, net $2,851 $ 210 $ 2 $3,063 Inventories 77 2 - 79 Total $2,928 $ 212 $ 2 3,142
Other assets 661 Total assets $3,803
12. QUARTERLY FINANCIAL DATA (UNAUDITED):
(Millions of Dollars) First Second Third Fourth Quarter Quarter Quarter Quarter Annual Total operating revenues $337 $289 $377 $335 $1,338 Operating income 74 52 93 63 282 Net Income 50 30 73 42 195
(Millions of Dollars) First Second Third Fourth Quarter Quarter Quarter Quarter Annual Total operating revenues $354 $311 $365 $315 $1,345 Operating income 79 59 90 57 285 Net Income 56 35 66 33 190
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
DIRECTORS
The directors listed below were elected April 24, 1997 to hold office until the next annual meeting of the Company's stockholders on April 23, 1998.
Name and Year First Became Director Age Principal Occupation; Directorships
Bill L. Amick 54 For more than five years, Chairman of the (1990) Board and Chief Executive Officer of Amick Farms, Inc., Batesburg, SC (vertically integrated broiler operation).
For more than five years, Chairman and Chief Executive Officer of Amick Processing, Inc. and Amick Broilers, Inc.
Director, SCANA Corporation, Columbia, SC.
James A. Bennett 37 Since December 1994, Senior Vice President (1997) and Director of Community Banking of First Citizens Bank, Columbia, SC.
From March 1991 to December 1994, President of Victory Savings Bank, Columbia, SC.
Director, SCANA Corporation
William B. Bookhart, Jr. 56 For more than five years, a partner in (1979) Bookhart Farms, Elloree, SC (general farming).
Director, SCANA Corporation, Columbia, SC.
William T. Cassels, Jr. 68 For more than five years, Chairman of the (1990) Board, Southeastern Freight Lines, Inc., Columbia, SC (trucking business).
Director, SCANA Corporation, Columbia, SC; Member, Advisory Board of Liberty Mutual Insurance Group.
Hugh M. Chapman 65 Since June 30, 1997, retired from (1988) NationsBank South, Atlanta, GA (a division of NationsBank Corporation, bank holding company).
For more than five years prior to June 30, 1997 Chairman of NationsBank South, Atlanta, GA
Director, SCANA Corporation, Columbia, SC; West Point-Stevens.
Name and Year First Became Director Age Principal Occupation; Directorships
Elaine T. Freeman 62 For more than five years, Executive Director (1992) of ETV Endowment of South Carolina, Inc. (non-profit organization), Spartanburg, SC.
Director, National Bank of South Carolina, Columbia, SC; SCANA Corporation, Columbia, SC.
Lawrence M. Gressette, Jr. 66 Since February 28, 1997, Chairman Emeritus (1987) of SCANA Corporation.
For more than five years prior to February 28, 1997, Chairman of the Board and Chief Executive Officer of SCANA Corporation and Chairman of the Board and Chief Executive Officer of all SCANA subsidiaries, including the Company.
For more than five years prior to December 13, 1995, President of SCANA Corporation.
Director, Wachovia Corporation, Winston- Salem, NC; Powertel, Inc., West Point, GA; SCANA Corporation, Columbia, SC.
W. Hayne Hipp 58 For more than five years, President and (1983) Chief Executive Officer, The Liberty Corporation, Greenville, SC (insurance and broadcasting holding company).
Director, The Liberty Corporation, Greenville, SC; Wachovia Corporation, Winston-Salem, NC; SCANA Corporation, Columbia, SC.
F. Creighton McMaster 68 For more than five years, President and (1974) Manager, Winnsboro Petroleum Company, Winnsboro, SC (wholesale distributor of petroleum products).
Director, First Union South Carolina, Greenville, SC; SCANA Corporation, Columbia, SC.
Lynne M. Miller 46 For more than five years, President of (1997) Environmental Strategies Corporation, Reston, VA (environmental consulting and engineering firm).
Director, SCANA Corporation, Columbia, SC.
John B. Rhodes 67 For more than five years, Chairman and (1967) Chief Executive Officer, Rhodes Oil Company, Inc., Walterboro, SC (distributor of petroleum products).
Director, SCANA Corporation, Columbia, SC.
Name and Year First Became Director Age Principal Occupation; Directorships
Maceo K. Sloan 48 For more than five years, Chairman, (1997) President and CEO of Sloan Financial Group, Inc. and Chairman, President and CEO of NCM Capital Management Group, Inc.
Director, SCANA Corporation, Columbia, SC.
William B. Timmerman 51 Since March 1, 1997, Chairman and Chief (1991) Executive Officer of SCANA Corporation.
From August 21, 1996 to March 1, 1997, Chief Operating Officer of SCANA Corporation.
Since December 13, 1995, President of SCANA Corporation.
From May 1, 1994 to December 13, 1995, Executive Vice President of SCANA Corporation.
Since August 25, 1993, Assistant Secretary of SCANA Corporation and all of its subsidiaries, including the Company.
From August 28, 1991 to February 20, 1996, Chief Financial Officer of the Company.
For more than five years prior to May 1, 1994, Senior Vice President of SCANA Corporation.
For more than five years prior to February 20, 1996, Controller of SCANA Corporation.
Director, SCANA Corporation, Columbia, SC; Powertel, Inc., West Point, GA, ITC^DeltaCom Board Member, West Point, GA. and Wachovia Bank, N. A., Columbia, S. C.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
All of the Company's common stock is held by its parent, SCANA Corporation. The required forms indicate that no equity securities of the Company are owned by its directors and executive officers. Based solely on a review of the copies of such forms and amendments furnished to the Company and written representations from the executive officers and directors, the Company believes that during 1997 all Section 16(a) filing requirements applicable to its executive officers, directors and greater than 10% beneficial owners were complied with.
ITEM 11.
ITEM 11. EXECUTIVE COMPENSATION
The following table contains information with respect to compensation paid or accrued during the years 1997, 1996 and 1995 to the Chief Executive Officer of the Company, to each of the other four most highly compensated executive officers of the Company during 1997, who were serving as executive officers of the Company at the end of 1997 and to L. M. Gressette, Jr., the Company's former Chief Executive Officer, who retired in February 1997.
Payouts will occur when SCANA's Total Shareholder Return ("TSR") is in the top two-thirds of a peer group of utilities, and will vary based on SCANA's ranking against the peer group. Executives earn threshold payouts at the 33rd percentile of three-year performance. Target payouts will be made at the 50th percentile of three-year performance. Maximum payouts will be made when the TSR is at or above the 75th percentile of the peer group. Payments will be made on a sliding scale for performance between threshold and target and target and maximum. No payouts will be earned if performance is at less than the 33rd percentile. Awards are denominated in shares of SCANA Common Stock and may be paid in either stock or cash or a combination of both.
DEFINED BENEFIT PLANS
In addition to the qualified Retirement Plan for all employees, SCANA has Supplemental Executive Retirement Plans ("SERPs") for certain eligible employees, including officers of its subsidiaries. A SERP is an unfunded plan which provides for benefit payments in addition to those payable under a qualified retirement plan. It maintains uniform application of the Retirement Plan benefit formula and would provide, among other benefits, payment of Retirement Plan formula pension benefits, if any, which exceed those payable under the Internal Revenue Code ("IRC") maximum benefit limitations.
The following table illustrates the estimated maximum annual benefits payable upon retirement at normal retirement date under the Retirement Plan and the SERPs.
Pension Plan Table
Final Service Years Average Pay 15 20 25 30 35
$150,000 $ 41,965 $ 55,953 $ 69,942 $ 83,930 $ 86,668 200,000 56,965 75,953 94,942 113,930 117,918 250,000 71,965 95,953 119,942 143,930 149,168 300,000 86,965 115,953 144,942 173,930 180,418 350,000 101,965 135,953 169,942 203,930 211,668 400,000 116,965 155,953 194,942 233,930 242,918 450,000 131,965 175,953 219,942 263,930 274,168
500,000 146,965 195,953 244,942 293,930 305,418
550,000 161,965 215,953 269,942 323,930 336,668 600,000 176,965 235,953 294,942 353,930 367,918 650,000 191,965 255,953 319,942 383,930 399,168 700,000 206,965 275,953 344,942 413,930 430,418 750,000 221,965 295,953 369,942 443,930 461,668
800,000 236,965 315,953 394,942 473,930 492,918
For all the executive officers named in the Summary Compensation Table for 1997, the compensation shown in the column labeled "Salary" of the Summary Compensation Table is covered by the Retirement Plan and/or a SERP. As of December 31, 1997, Messrs. Timmerman, Skolds, Bullwinkel, Marsh and Darby had credited service under the Retirement Plan (or its equivalent under the SERP) of 19, 11, 26, 13 and 29 years, respectively. Mr. Gressette currently is receiving a monthly benefit of $28,380 under the Retirement Plan and a SERP. Benefits are computed based on a straight-life annuity with an unreduced 60% surviving spouse benefit. The amounts in this table assume continuation of the primary Social Security benefits in effect at January 1, 1998, and are not subject to any deduction for Social Security or other offset amounts.
The Company also has a Key Employee Retention Plan (the "Key Employee Retention Plan") covering officers and certain other executive employees that provides supplemental retirement and/or death benefits for participants. Under the plan, each participant may elect to receive either (i) a monthly retirement benefit for 180 months upon retirement at or after age 65, equal to 25% of the average monthly salary of the participant over his final 36 months of employment prior to age 65, or (ii) an optional death benefit payable monthly to a participant's designated beneficiary for 180 months, in an amount equal to 35% of the average monthly salary of the participant over his final 36 months of employment prior to age 65. In the event of the participant's death prior to age 65, the Company will pay to the participant's designated beneficiary for 180 months, a monthly benefit equal to 50% of such participant's base monthly salary in effect at death.
All of the executive officers named in the Summary Compensation Table are participating in the plan. Mr. Gressette is receiving an annual benefit of $113,854 under the Key Employee Retention Plan. The estimated annual retirement benefits payable at age 65, based on projected eligible compensation (assuming increases of 4% per year) to the other persons named in the Summary Compensation Table are as follows: Mr. Timmerman-$170,199; Mr. Skolds-$135,858; Mr. Bullwinkel-$96,589 ; Mr. Marsh-$119,695 and Mr. Darby-$67,006.
TERMINATION, SEVERANCE AND CHANGE IN CONTROL ARRANGEMENTS
Since its approval by the Board on December 18, 1996, SCANA Corporation has maintained an Executive Benefit Plan Trust (the "Trust"). The purpose of the Trust and the related plans is to help retain and attract quality leadership in key company positions in the current transitional environment of the electric utility industry. The Trust is used to receive contributions which may be used to pay the deferred compensation benefits of certain directors, executives and other key employees of SCANA and its subsidiaries' in the event of a Change in Control (as defined in the Trust). All the executive officers named in the Summary Compensation Table participate in certain of the plans listed below (the "Plans") which are covered by the Trust.
(1) SCANA Corporation Voluntary Deferral Plan (2) SCANA Corporation Supplementary Voluntary Deferral Plan (3) SCANA Corporation Key Employee Retention Plan (4) SCANA Corporation Supplemental Executive Retirement Plan (5) SCANA Corporation Performance Share Plan (6) SCANA Corporation Annual Incentive Plan (7) SCANA Corporation Key Executive Severance Benefits Plan (8) SCANA Corporation Supplementary Key Executive Severance Benefits Plan
The Trust and the Plans provide flexibility to the Company in responding to a Potential Change in Control (as defined in the Trust) depending upon whether the Change in Control would be viewed as being "hostile" or "friendly". This flexibility includes the ability to deposit and withdraw Company contributions up to the point of a Change in Control, and to affect the number of plan participants who may be eligible for benefit distributions upon, or following, a Change in Control. The Plans listed above at items (7) and (8) cover all the named executive officers (except Mr. Gressette).
The Key Executive Severance Benefits Plan is operative as a "single trigger" plan, meaning that upon the occurrence of a "hostile" Change in Control, benefits provided under plans (1) through (6) above would be distributed in a lump sum. Under the terms of the Trust, in the event of a Change in Control that would trigger operation of the Key Executive Severance Benefits Plan, Mr. Gressette would receive immediate payout of all benefits under any of the Plans in which he is then participating.
In contrast, the Supplementary Key Executive Severance Benefits Plan (the "Supplementary Plan") is operative for a period of twenty-four months following a Change in Control which prior to its occurrence is viewed as being "friendly". In this circumstance, the Key Executive Severance Benefits Plan is inoperative. The Supplementary Plan is a "double trigger" plan that would pay benefits in lieu of those otherwise provided under plans (1) through (6) in either of two circumstances: (a) the participant's involuntary termination of employment without "Just Cause", or (b) the participant's voluntary termination of employment for "Good Reason" (as these terms are defined in the Supplementary Plan).
Benefit distributions relative to a Change in Control, as to which either the Key Executive Severance Benefits Plan or the Supplementary Plan is operative, will be grossed up to include estimated federal, state and local income taxes and any applicable excise taxes owed by Plan participants on those benefits, and paid in a lump sum. The benefit distributions would also be calculated so as to include, in addition to other benefits:
(a) Three times the sum of: (1) the officer's annual base salary in effect as of the Change in Control and (2) the larger of (i) the officer's full targeted annual incentive opportunity in effect as of the Change in Control under the Annual Incentive Plan, or (ii) the officer's average of actual annual incentive bonuses received during the prior three years under the Annual Incentive Plan; and
(b) an amount equal to the projected cost for coverage for three full years following the Change in Control as though the officer had continued to be a Company employee with respect to medical coverage, long-term disability coverage and either Life Plus (a special life insurance program combining whole life and term coverages) or group term life coverage in accordance with the officer's actual election, in each case so as to provide substantially the same level of coverage and benefits as the officer enjoyed as of the date of the Change in Control.
Benefit distributions pertaining to the Voluntary Deferral Plan would be calculated as of the date of the Change in Control inclusive of interest provided under the plan through such date, and benefits pertaining to the Supplementary Voluntary Deferral Plan would be calculated to include any implied dividends accruable under the plan through the date of the Change in Control.
Benefit distributions pertaining to the Key Employee Retention Plan would be calculated inclusive of projected increases to each participant's base salary using a fixed, market competitive rate as though the participant had reached the earlier of age 65 or completed 35 years of service.
Benefit distributions pertaining to the Supplemental Executive Retirement Plan would be calculated as an actuarial equivalent through the date of the Change in Control with three additional years of compensation at the participant's rate then in effect as though the participant had attained age 65 and completed 35 years of benefit service as of the date of the Change in Control and without any early retirement or other actuarial reductions, which benefit would then be reduced by the actuarial equivalent of the participant's qualified plan benefit amount under the Retirement Plan.
Benefit distributions pertaining to the Performance Share Plan would be equal to 100% of the targeted award as granted for all performance periods which are not yet completed as of the date of the Change in Control. Benefit distributions pertaining to the Annual Incentive Plan would be equal to 100% of the target award.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
During 1997, no officer, employee or former officer of SCANA or any of its subsidiaries served as a member of the Long-Term Compensation Committee or the Performance Committee, except Mr. Gressette who served as an ex-officio, non-voting member of the Performance Committee until his retirement in February 1997 and as a member of the Long-Term Compensation Committee following his retirement, and Mr. Timmerman who has been an ex-officio, non- voting member of the Performance Committee since March 1, 1997. Although Mr. Gressette and Mr. Timmerman served as members of the Performance Committee during 1997, neither participated in any of its decisions concerning executive officer compensation. As a member of the Long-Term Compensation Committee following his retirement, Mr. Gressette participated in the decisions regarding target awards made in 1997 under the Performance Share Plan.
Since January 1, 1997, SCANA and its subsidiaries including the Company have engaged in business transactions with entities with which Mr. Amick (a member of the Performance Committee and the Long-Term Compensation Committee), Mr. Chapman (Chairman of both the Performance Committee and the Long-Term Compensation Committee) and Mr. McMaster (a member of the Long-Term Compensation Committee) are related.
Mr. Amick is the owner of Team Amick Motor Sports, a business that owns and operates a NASCAR sanctioned racing car. This car participates in the Busch Grand National Racing Series. SCANA has entered into a shared sponsorship agreement with Team Amick Motor Sports pursuant to which SCANA will receive promotional considerations associated with NASCAR racing for an annual fee of $500,000.
Mr. Chapman was Chairman of NationsBank South, a division of NationsBank Corporation until his retirement on June 30, 1997. Since January 1, 1997, SCANA has engaged in various transactions in which affiliates of NationsBank Corporation acted as lender or provider of lines of credit or credit support to SCANA and its subsidiaries. The amount paid during 1997, by SCANA and its subsidiaries to NationsBank Corporation affiliates on account of such transactions was $361,870. In addition, during 1997, a NationsBank Corporation affiliate and a SCANA subsidiary have engaged in options and futures transactions and forward contracts relating to forecasted natural gas production. The amount paid during 1997, by a SCANA subsidiary to NationsBank Corporation affiliates on account of such transactions was $7,602,582. It is anticipated that similar transactions will continue in the future.
Mr. McMaster is the President and Manager of Winnsboro Petroleum Company. Purchases from Winnsboro Petroleum Company totaling $61,819 for petroleum products were made during 1997, by the Company and its subsidiaries. It is anticipated that similar transactions will continue.
Compensation of Directors
Fees. During 1997, directors who were not employees of the Company were paid $17,600 annually for services rendered as directors of SCANA and its subsidiaries, including the Company, $1,800 for each Board meeting attended and $850 for attendance at a committee meeting which is not held on the same day as a regular meeting of the Board. The fee for attendance at a telephone conference meeting is $200. The fee for attendance at a conference is $850. In addition, directors are paid, as part of their compensation, travel, lodging and incidental expenses related to attendance at meetings and conferences. The Board of Directors approved a plan effective January 1, 1997, whereby non-employee directors receive on a quarterly basis, 41% of their retainer in shares of SCANA common stock. The purpose of the plan is to promote the achievement of long-term objectives of SCANA by linking the personal interests of the non-employee directors to those of SCANA's shareholders by paying a portion of director compensation in stock. The Company believes this linkage will further promote the achievement of its long-term objectives.
Directors who are employees of SCANA or its subsidiaries receive no compensation for serving as directors or attending meetings.
In addition to regular director fees which he began to receive following his retirement, Mr. Gressette, as a Company retiree, received the retirement benefits described in the Summary Compensation Table on page 64.
Deferral Plan. SCANA has a plan (the "Voluntary Deferral Plan") pursuant to which directors may defer all or a portion of their fees paid to them in cash for services rendered and meeting attendance. Interest is earned on the deferred amounts at a rate set by the Management Development and Corporate Committee (the Performance Committee). Since January 1, 1997, the rate has been set at the announced prime rate of Wachovia Bank, N. A. Mr. Cassels and Mr. Rhodes were the only directors participating in the plan during 1997. Mr. Cassels became a participant in January 1994, and Mr. Rhodes in July 1987. Interest credited to their deferral accounts during 1997, was $8,609 and $27,228, respectively.
Endowment Plan. Upon election to a second term, each director becomes eligible to participate in the Directors' Endowment Plan, which provides for the Company to make a tax deductible, charitable contribution totaling $500,000 to institutions of higher education designated by the SCANA director. A portion is contributed upon retirement of the director and the remainder upon the director's death. The plan is funded in part through insurance on the lives of the directors. Designated in-state institutions of higher education must be approved by the Chief Executive Officer. Any out-of-state designation must be approved by the Performance Committee. The designated institutions are reviewed on an annual basis by the Chief Executive Officer to assure compliance with the intent of the program. The plan is intended to reinforce the commitment to quality higher education and is intended to enhance the ability to attract and retain qualified board members.
ITEM 12.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The table set forth below indicates the shares of SCANA's common stock beneficially owned as of March 10, 1998 by each director, each of the persons named in the Summary Compensation Table on page 64 (the "Named Executive Officer"), the directors and current executive officers of the Company as a group.
SECURITY OWNERSHIP OF MANAGEMENT
Name of Beneficial Amount and Nature Name of Beneficial Amount and Nature Owner of Ownership 1 Owner of Ownership 1 B. L. Amick 3,355 W. Hayne Hipp 3,145 J. A. Bennett 669 K. M. Marsh 9,760 W. B. Bookhart, Jr. 17,973 F. C. McMaster 5,975 G. J. Bullwinkel 20,167 L. M. Miller 1,281 W. T. Cassels, Jr. 2,355 J. B. Rhodes 9,052 H. M. Chapman 6,345 J. L. Skolds 9,473 W. A. Darby 23,336 M. K. Sloan 581 E. T. Freeman 4,675 W. B. Timmerman 28,567 L. M. Gressette, Jr. 59,352
All directors and executive officers as a group (17 persons) TOTAL 206,061. TOTAL PERCENT OF CLASS 0.2%
- ---------- 1 Includes shares owned by close relatives, the beneficial ownership of which is disclaimed by the director, nominee or Named Executive Officers, as follows:
Mr. Amick - 480; Mr. Bookhart - 5,029; Mr. Gressette - 1,060; and Mr. McMaster - 2,000; and by all directors, nominees and current executive officers - 8,569 in total.
Includes shares purchased through December 31, 1997, but not thereafter, by the Trustee under the Company's Stock Purchase- Savings Plan (the Savings Plan).
The information set forth above as to the security ownership of common stock has been furnished to the Company by such persons.
ITEM 13.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
For information regarding certain relationships and related transactions, see Item 11, "Compensation Committee Interlocks and Insider Participation."
PART IV
ITEM 14.
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
Financial Statements and Schedules
See Index to Consolidated Financial Statements and Supplementary Data on page 33.
Exhibits Filed
Exhibits required to be filed with this Annual Report on Form 10-K are listed in the Exhibit Index following the signature page. Certain of such exhibits which have heretofore been filed with the Securities and Exchange Commission and which are designated by reference to their exhibit number in prior filings are hereby incorporated herein by reference and made a part hereof.
As permitted under Item 601(b)(4)(iii), instruments defining the rights of holders of long-term debt of less than 10 percent of the total consolidated assets of the Company and its subsidiaries, have been omitted and the Company agrees to furnish a copy of such instruments to the Commission upon request.
Reports on Form 8-K
None
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.
(REGISTRANT) SOUTH CAROLINA ELECTRIC & GAS COMPANY
BY (SIGNATURE) s/J. L. Skolds (NAME AND TITLE) J. L. Skolds, President and Chief Operating Officer DATE February 17, 1998
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.
(i) Principal executive officer:
BY (SIGNATURE) s/W. B. Timmerman (NAME AND TITLE) W. B. Timmerman Chairman of the Board, Chief Executive Officer and Director DATE February 17, 1998
(ii) Principal financial officer:
BY (SIGNATURE) s/K. B. Marsh (NAME AND TITLE) K. B. Marsh, Chief Financial Officer DATE February 17, 1998
(iii) Principal accounting officer:
BY (SIGNATURE) s/J. E. Addison (NAME AND TITLE) J. E. Addison, Vice President and Controller DATE February 17, 1998
BY (SIGNATURE) s/B. L. Amick (NAME AND TITLE) B. L. Amick, Director DATE February 17, 1998
BY (SIGNATURE) s/J. A. Bennett (NAME AND TITLE) J. A. Bennett, Director DATE February 17, 1998
BY (SIGNATURE) s/W. B. Bookhart, Jr. (NAME AND TITLE) W. B. Bookhart, Jr., Director DATE February 17, 1998
BY (SIGNATURE) s/W. T. Cassels, Jr. (NAME AND TITLE) W. T. Cassels, Jr., Director DATE February 17, 1998
BY (SIGNATURE) s/H. M. Chapman (NAME AND TITLE) H. M. Chapman, Director DATE February 17, 1998
BY (SIGNATURE) s/E. T. Freeman (NAME AND TITLE) E. T. Freeman, Director DATE February 17, 1998
BY (SIGNATURE) s/L. M. Gressette, Jr. (NAME AND TITLE) L. M. Gressette, Jr., Director DATE February 17, 1998
BY (SIGNATURE) s/W. Hayne Hipp (NAME AND TITLE) W. Hayne Hipp, Director DATE February 17, 1998
BY (SIGNATURE) s/F. C. McMaster (NAME AND TITLE) F. C. McMaster, Director DATE February 17, 1998
BY (SIGNATURE) s/L. M. Miller (NAME AND TITLE) L. M. Miller, Director DATE February 17, 1998
BY (SIGNATURE) s/J. B. Rhodes (NAME AND TITLE) J. B. Rhodes, Director DATE February 17, 1998
BY (SIGNATURE) s/M. K. Sloan (NAME AND TITLE) M. K. Sloan, Director DATE February 17, 1998
SOUTH CAROLINA ELECTRIC & GAS COMPANY Sequentially EXHIBIT INDEX Numbered Number Pages 2. Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession Not Applicable
3. Articles of Incorporation and By-Laws
A. Restated Articles of Incorporation of the Company as adopted on December 15, 1993 (Exhibit 3-A to Form 10-Q for the quarter ended June 30, 1994, File No. 1-3375).................... # B. Articles of Amendment, dated June 7, 1994, filed June 9, 1994 (Exhibit 3-B to Form 10-Q for the quarter ended June 30, 1994, File No. 1-3375).... # C. Articles of Amendment, dated November 9, 1994 (Exhibit 3-C to Form 10-K for the year ended December 31, 1994, File No. 1-3375)...................... # D. Articles of Amendment, dated December 9, 1994 (Exhibit 3-D to Form 10-K for the year ended December 31, 1994, File No. 1-3375)...................... # E. Articles of Correction, dated January 17, 1995 (Exhibit 3-E to Form 10-K for the year ended December 31, 1994, File No. 1-3375)...................... # F. Articles of Amendment, dated January 13, 1995 and filed January 17, 1995 (Exhibit 3-F to Form 10-K for the year ended December 31, 1994, File No. 1-3375)......................................... # G. Articles of Amendment dated March 31, 1995 (Exhibit 3-G to Form 10-Q for the quarter ended March 31, 1995, File No. 1-3375)................... # H. Articles of Correction - Amendment to Statement filed March 31, 1995, dated December 13, 1995 (Exhibit 3-H to Form 10-K for the year ended December 31. 1995, File No. 1-3375)...................... # I. Articles of Amendment dated December 13, 1995 (Exhibit 3-I to Form 10-K for the year ended December 31, 1995, File No. 1-3375)...................... # J. Copy of By-Laws of the Company as revised and amended on December 17, 1997 (Filed herewith)............ 77 K. Articles of Amendment dated February 18, 1997 (Exhibit 3-L to Registration Statement No. 333-24919).... # L. Articles of Amendment dated February 21, 1997 (Exhibit 3-L to Form 10-Q for the quarter ended March 31, 1997).......................................... # M. Articles of Amendment dated April 22, 1997 (Exhibit 3-M to Form 10-Q for the quarter ended June 30, 1997)..................................... #
4. Instruments Defining the Rights of Security Holders, Including Indentures A. Indenture dated as of January 1, 1945, from the South Carolina Power Company (the "Power Company") to Central Hanover Bank and Trust Company, as Trustee, as supplemented by three Supplemental Indentures dated respectively as of May 1, 1946, May 1, 1947 and July 1, 1949 (Exhibit 2-B to Registration No. 2-26459)................................ # B. Fourth Supplemental Indenture dated as of April 1, 1950, to Indenture referred to in Exhibit 4A, pursuant to which the Company assumed said Indenture (Exhibit 2-C to Registration No. 2-26459)...... #
# Incorporated herein by reference as indicated.
SOUTH CAROLINA ELECTRIC & GAS COMPANY Exhibit Index (Continued) Sequentially Numbered Number Pages
4. (continued) C. Fifth through Fifty-second Supplemental Indentures to Indenture referred to in Exhibit 4A dated as of the dates indicated below and filed as exhibits to the Registration Statements and 1934 Act reports whose file numbers are set forth below..................................................... # December 1, 1950 Exhibit 2-D to Registration No. 2-26459 July 1, 1951 Exhibit 2-E to Registration No. 2-26459 June 1, 1953 Exhibit 2-F to Registration No. 2-26459 June 1, 1955 Exhibit 2-G to Registration No. 2-26459 November 1, 1957 Exhibit 2-H to Registration No. 2-26459 September 1, 1958 Exhibit 2-I to Registration No. 2-26459 September 1, 1960 Exhibit 2-J to Registration No. 2-26459 June 1, 1961 Exhibit 2-K to Registration No. 2-26459 December 1, 1965 Exhibit 2-L to Registration No. 2-26459 June 1, 1966 Exhibit 2-M to Registration No. 2-26459 June 1, 1967 Exhibit 2-N to Registration No. 2-29693 September 1, 1968 Exhibit 4-O to Registration No. 2-31569 June 1, 1969 Exhibit 4-C to Registration No. 33-38580 December 1, 1969 Exhibit 4-Q to Registration No. 2-35388 June 1, 1970 Exhibit 4-R to Registration No. 2-37363 March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324 January 1, 1972 Exhibit 4-C to Registration No. 33-38580 July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291 May 1, 1975 Exhibit 4-C to Registration No. 33-38580 July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908 February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304 December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936 March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662 May 1, 1977 Exhibit 4-C to Registration No. 33-38580 February 1, 1978 Exhibit 4-C to Registration No. 33-38580 June 1, 1978 Exhibit 2-A-3 to Registration No. 2-61653 April 1, 1979 Exhibit 4-C to Registration No. 33-38580 June 1, 1979 Exhibit 4-C to Registration No. 33-38580 April 1, 1980 Exhibit 4-C to Registration No. 33-38580 June 1, 1980 Exhibit 4-C to Registration No. 33-38580 December 1, 1980 Exhibit 4-C to Registration No. 33-38580 April 1, 1981 Exhibit 4-D to Registration No. 33-49421 June 1, 1981 Exhibit 4-D to Registration No. 2-73321 March 1, 1982 Exhibit 4-D to Registration No. 33-49421 April 15, 1982 Exhibit 4-D to Registration No. 33-49421 May 1, 1982 Exhibit 4-D to Registration No. 33-49421 December 1, 1984 Exhibit 4-D to Registration No. 33-49421 December 1, 1985 Exhibit 4-D to Registration No. 33-49421 June 1, 1986 Exhibit 4-D to Registration No. 33-49421 February 1, 1987 Exhibit 4-D to Registration No. 33-49421 September 1, 1987 Exhibit 4-D to Registration No. 33-49421 January 1, 1989 Exhibit 4-D to Registration No. 33-49421 January 1, 1991 Exhibit 4-D to Registration No. 33-49421 February 1, 1991 Exhibit 4-D to Registration No. 33-49421 July 15, 1991 Exhibit 4-D to Registration No. 33-49421 August 15, 1991 Exhibit 4-D to Registration No. 33-49421 April 1, 1993 Exhibit 4-E to Registration No. 33-49421 July 1, 1993 Exhibit 4-D to Registration No. 33-57955 D. Indenture dated as of April 1, 1993 from South Carolina Electric & Gas Company to NationsBank of Georgia, National Association (Filed as Exhibit 4-F to Registration Statement No. 33-49421)......................................... # E. First Supplemental Indenture to Indenture referred to in 4-D dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421)......................... #
# Incorporated herein by reference as indicated.
SOUTH CAROLINA ELECTRIC & GAS COMPANY EXHIBIT INDEX
Exhibit Index (Continued) Sequentially Numbered Number Pages F. Second Supplemental Indenture to Indenture referred to in 4-D dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955)......................... # G. Trust Agreement for SCE&G Trust I (Filed herewith).............. 93 H. Certificate of Trust for SCE&G Trust I (Filed herewith)......... 96 I. Form of Junior Subordinated Indenture for SCE&G Trust I (Filed herewith)................................................ 97 J. Form of Guarantee Agreement for SCE&G Trust I (Filed herewith)....................................................... 177 K. Form of Amended & Restated Trust Agreement for SCE&G Trust I (Filed herewith)........................................ 198
9. Voting Trust Agreement Not Applicable
10. Material Contracts A. Copy of Supplemental Executive Retirement Plan (Exhibit 10-A to Form 10-K for the year ended December 31, 1980)............................................ 276
11. Statement Re Computation of Per Share Earnings Not Applicable
12. Statement re Computation of Ratios (Filed herewith)................ 295
13. Annual Report to Security Holders, Form 10-Q or Quarterly Report to Security Holders Not Applicable
16. Letter Re Change in Certifying Accountant Not Applicable
18. Letter Re Change in Accounting Principles Not Applicable
21. Subsidiaries of the Registrant Not Applicable
22. Published Report Regarding Matters Submitted to Vote of Security Holders Not Applicable
23. Consents of Experts and Counsel Consent of Deloitte & Touche LLP................................... 299
24.