Annual Report (Form 10-K), fiscal year 1993

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 4,166 full-time, permanent employees as of December 31, 1993 as compared to 4,168 full-time, permanent employees as of December 31, 1992.
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 and Service Area
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 areas of Columbia and Charleston, South Carolina. The Company's business is seasonal in that, 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 29 of the 46 counties in South Carolina and covers more than 19,000 square miles. Total estimated population of the counties representing the Company's combined service area is approximately 2.3 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, 1993, 1992 and 1991 is contained in Note 11 of Notes to Consolidated Financial Statements and all such information is incorporated herein by reference.
CAPITAL REQUIREMENTS AND FINANCING PROGRAM
Capital Requirements
The cash requirements of the Company arise primarily from its operational needs and its construction program. During 1994 the Company is expected to meet its capital requirements principally through internally generated funds (approximately 32% excluding dividends), the issuance and sale of debt securities and additional equity contributions from SCANA. Short-term liquidity is expected to be provided 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 recovers the costs of providing services through rates charged to customers. Rates for regulated services are based on historical costs. As inflation occurs and the Company expands its construction program it is necessary to seek increases in rates, and on June 7, 1993 the PSC issued an order granting the Company a 7.4% annual increase, based on a test year, in retail electric rates to be implemented in two phases of $42.0 million annually effective June 1993 and $18.5 million annually effective June 1994. The Company's future financial position and results of operations will be affected by its ability to obtain adequate and timely rate relief. (See "Regulation.")
The Company's estimates of its cash requirements for construction and nuclear fuel expenditures, which are subject to continuing review and adjustment, for 1994 and the four-year period 1995-1998 as now scheduled are as follows:
Type of Facilities 1994 1995-1998 (Thousands of Dollars) Electric Plant: Generation. . . . . . . . . . . . . . . . $245,039 $ 539,180 Transmission. . . . . . . . . . . . . . . 21,230 94,177 Distribution. . . . . . . . . . . . . . . 58,178 295,523 Other . . . . . . . . . . . . . . . . . . 12,815 42,975 Nuclear Fuel. . . . . . . . . . . . . . . . 28,064 84,770 Gas . . . . . . . . . . . . . . . . . . . . 15,814 62,276 Transit . . . . . . . . . . . . . . . . . . 422 749 Common. . . . . . . . . . . . . . . . . . . 30,650 54,715 Nonutility . . . . . . . . . . . . . . . . 139 545 Total . . . . . . . . . . . . . . $412,351 $1,174,910
The above estimates exclude AFC.
Construction
The Company's cost estimates for its construction program for the periods 1994 and 1995-1998 shown in the above table include costs of the projects described below.
The Company entered into a contract with Duke/Fluor Daniel in 1991 to design, engineer and build a 385 MW coal-fired electric generating plant near Cope, South Carolina in Orangeburg County. Construction of the plant began in November 1992 with commercial operation expected in late 1995 or early 1996. The estimated price of the Cope plant, excluding financing costs and AFC but including an allowance for escalation, is $450 million. In addition, the transmission lines for interconnection with the Company's system are expected to cost $26 million.
The steam generators at Summer Station will be replaced during the 1994 regularly scheduled refueling outage. In January 1994 the Company, acting on behalf of itself and the PSA (as co- owners of the 885 Megawatt Summer Station), reached a settlement with Westinghouse Electric Corporation (Westinghouse) resolving a dispute involving steam generators provided by Westinghouse to Summer Station which are defective in design, workmanship and materials. Terms of the settlement are confidential by agreement of the parties and order of the court. The Company had filed an action in May 1990 against Westinghouse in the U. S. District Court for South Carolina; an order dismissing this suit was issued on January 12, 1994.
During 1993 the Company expended approximately $20 million as part of a program to extend the operating lives of certain generating facilities. Additional improvements under the program to be made during 1994 are estimated to cost approximately $17 million.
Financing Program
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 12 consecutive months out of the 15 months prior to the month of issuance is at least twice the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 1993 the Bond Ratio was 3.70. The issuance of additional Class A Bonds is restricted also to an additional principal amount equal to 60% of unfunded net property additions (which unfunded net property additions totaled approximately $219.9 million at December 31, 1993), Class A Bonds issued on the basis of retirements of Class A Bonds (which retirement credits totaled $10.9 million at December 31, 1993), and Class A Bonds issued on the basis of cash on deposit with the Trustee.
The Company has placed a new bond indenture (New Mortgage) dated April 1, 1993 on substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are expected to be 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 $157 million were available for such purpose as of December 31, 1993), 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 12 consecutive months out of the 18 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, 1993 the New Bond Ratio was 5.0.
On April 29, 1993 the Securities and Exchange Commission declared effective a registration statement for the issuance of up to $700 million of New Bonds. The following series, aggregating $600 million, have been issued under such registration statement:
On June 9, 1993, $100 million, 7 5/8% Series due June 1, 2023 to repay short-term borrowings in a like amount.
On July 1, 1993, $100 million, 6% Series due June 15, 2000, and $150 million, 7 1/8% Series due June 15, 2013, and on July 20, 1993, $150 million, 7 1/2% Series due June 15, 2023, to redeem, on July 20, 1993, $382,035,000 of First and Refunding Mortgage Bonds maturing between 1999 and 2017 and bearing interest at rates between 8% and 9 7/8% per annum.
On December 20, 1993. $100 million, 6 1/4% Series due December 15, 2003 to repay short-term borrowings in a like amount.
On June 1, 1993 the Company redeemed the following amounts of First and Refunding Mortgage Bonds: $35 million, 10 1/8% Series due 2009 and $13 million, 9 7/8% Series due 2009.
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; provided, however, that 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 FERC authority to issue short-term indebted- ness. The FERC has authorized the Company to issue up to $200 million of unsecured promissory notes or commercial paper with maturity dates of 12 months or less but not later than December 31, 1995.
The Company has $127.0 million authorized and unused lines of credit at December 31, 1993.
SCE&G'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 12 consecutive months immediately preceding the month of issuance is 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, 1993 the Preferred Stock Ratio was 2.52.
The ratio of earnings to fixed charges (SEC Method) was 3.57, 2.73, 3.32, 3.33 and 3.04 for the years ended December 31, 1993, 1992, 1991, 1990 and 1989, respectively.
Additional Capital Requirements
In addition to the Company's capital requirements for 1994 described above, approximately $5.0 million will be required for refunding and retiring outstanding securities and obligations. For the years 1995-1998, the Company has an aggregate of $149.4 million of long-term debt maturing (including approximately $43.9 million for sinking fund requirements, of which $43.5 million may be satisfied by deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits) and $9.9 million of purchase or sinking fund requirements for preferred stock.
Actual 1994 expenditures may vary from the estimates set forth above due to factors such as inflation, economic conditions, regulation, legislation, rates of load growth, environmental protection standards and the cost and availability of capital.
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 fuel. To finance nuclear and fossil fuel inventories, Fuel Company issues, from time to time, its promissory notes with maturities of less than 270 days ("Commercial Paper"). The issuance of Commercial Paper is supported by an irrevocable revolving credit agreement which expires July 31, 1996 and is guaranteed by the Company. Accordingly, the amounts outstanding have been included in long- term debt. The credit agreement provides for a maximum amount of $75 million that may be outstanding at any time.
At December 31, 1993 Commercial Paper outstanding for nuclear and fossil fuel inventories was approximately $36.8 million at a weighted average interest rate of 3.47%. Such fuel inventories and fuel-related assets and liabilities are included in the Company's financial statements. (See Notes 1 and 4 of Notes to Consolidated Financial Statements.)
ELECTRIC OPERATIONS
Electric Sales
In 1993 residential sales of electricity accounted for 43% of electric sales revenues; commercial sales 29%; industrial sales 21%; sales for resale 4%; and all other 3%. KWH sales by classification for the years ended December 31, 1993 and 1992 are presented below:
Sales KWH % Classification 1993 1992 Change (thousands)
Residential 5,650,759 5,155,886 9.50 Commercial 4,844,422 4,538,862 6.73 Industrial 4,887,250 4,684,072 4.34 Sale for resale 1,005,968 946,357 6.30 Other 500,937 476,064 5.22 Total Territorial 16,889,336 15,801,241 6.89
Interchange 198,059 77,046 157.07 Total 17,087,395 15,878,287 7.61
The Company furnishes electricity for resale to three municipalities, three investor-owned utilities, two electric cooperatives and one public power authority. Such sales for resale accounted for 4% of total electric sales revenues in 1993.
An addition of 6,973 electric customers to 468,901 total customers contributed to an all-time peak demand record of 3,557 on July 29, 1993. The previous years' record of 3,380 MW was set July 13, 1992.
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.
The Company's transmission system is part of the interconnected grid extending over a large part of the southern and eastern portion 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 which 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 1991-1993.
1991 1992 1993 Nuclear: Per million BTU $ .57 $ .52 $ .47 Coal: Company: Per ton $41.61 $40.00 $39.95 Per million BTU 1.63 1.56 1.55 GENCO: Per ton $42.12 $41.82 $41.64 Per million BTU 1.64 1.63 1.62 Weighted Average Cost of All Fuels: Per million BTU $ 1.38 $ 1.27 $ 1.33
The fuel costs 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 KWH generation (including Williams Station) by each category of fuel for the years 1991-1993 and the estimates for 1994 and 1995.
Percent of Total KWH Generated Actual Estimated 1991 1992 1993 1994 1995
Coal 68% 65% 72% 77% 69% Nuclear 21 29 22 17 26 Hydro 5 5 5 5 5 Natural Gas & Oil 6 1 1 1 - 100% 100% 100% 100% 100%
Coal is currently used at all four of the Company's major fossil fuel-fired plants and GENCO's Williams Station. Unit train deliveries are used at all of these plants. On December 31, 1993 the Company had approximately a 73-day supply of coal in inventory and GENCO had approximately a 56-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 the following percentages of estimated requirements for 1994 (approximately 5.3 million tons, including requirements of Williams Station) and expire at the dates indicated (giving effect to the Company's potential to exercise renewal options):
Range of % of Final No. of Tons % of 1994 Sulfur Content Expiration Renegotiation Per Year Requirement per Contract Date (1) Date (1)
966,664 18.2 up to 1.55 02/28/2001 02/28/1995 360,000 6.8 1.00 - 1.80 12/31/2002 12/31/1996 134,000 2.5 1.10 - 2.00 03/31/1996 03/31/1994 120,000 2.3 1.10 - 1.60 04/30/1996 04/30/1994 972,000 18.3 up to 1.50 12/31/2002 12/31/1996 192,832 3.6 0.80 - 1.50 06/30/2000 06/30/1994 2,745,496 51.7
(1) Contract extensions beyond the stated renegotiation date to the final expiration date are subject to mutual agreement on price, terms, quantity and quality.
All of the above contracts, except the contracts expiring in March 1994 and April 1994 which have firm prices, are subject to periodic price adjustments based on changes in indices published by the U. S. Department of Labor.
Coal purchased in December 1993 had an average sulfur content of 1.17%, which permitted the Company to comply with existing environmental regulations. The Company believes that its operations are in substantial compliance with all existing regulations relating to the discharge of sulfur dioxide. The Company has not been advised by officials of DHEC that any more stringent sulfur content requirements for existing plants are contemplated. However, the Company will be required to meet the more stringent emissions standards established by the Clean Air Act (see "Environmental Control Matters").
The Company currently has adequate supplies of uranium under contract to manufacture nuclear fuel for Summer Station through 1996. The following table summarizes all contract commitments for the stages of nuclear fuel assemblies:
Commitment Contractor Regions(1) Term
Uranium NUEXCO Trading Corporation 11 1994 Uranium Energy Resources of Australia 9-13 1990-1996 Uranium Everest Minerals 9-13 1990-1996 Conversion Sequoyah Fuel Corp. 8-12 1989-1995 Enrichment DOE (2) Through 2022 Fabrication Westinghouse 1-21 1982-2009 Reprocessing None
(1) A region represents approximately one-third to one-half of the nuclear core in the reactor at any one time. Region no. 10 was loaded in 1993 and region no. 11 will be loaded in 1994. (2) The contract with the DOE is a "requirements" type contract whereby the DOE supplies total enrichment requirements for the unit through the year 2022, as specified by its then current schedule.
The Company has on-site spent fuel storage capability until at least 2008 and expects to be able to expand its storage capacity over the life of Summer Station 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 Control Matters" for information regarding the contract with the DOE for disposal of spent fuel.)
GAS OPERATIONS
Gas Sales
In 1993 residential sales accounted for 36% of gas sales revenues; commercial sales 26%; industrial sales 17% and transportation gas 21%. Dekatherm sales by classification for the years ended December 31, 1993 and 1992 are presented below:
SALES DEKATHERMS % CLASSIFICATION 1993 1992 CHANGE
Residential 12,009,444 11,286,088 6.4 Commercial 8,842,728 9,029,256 (2.1) Industrial 5,881,309 5,334,117 10.3 Transportation gas 6,993,817 5,906,697 18.4 Total 33,727,298 31,556,158 6.9
During 1993 the Company added 2,696 customers, increasing its total customers to 221,278.
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 alternative fuels and other factors.
The deregulation of natural gas prices at the wellhead which took place on January 1, 1985 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.
On April 8, 1992, the FERC promulgated its Order No. 636, which is 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 supplies whether the customer purchases gas from the pipeline or another supplier. The impact of this order on the Company will be primarily through changes affecting its supplier, Pipeline Corporation, which, while operating wholly within the state of South Carolina, is served by two interstate pipelines.
To reduce dependence on imported oil, NEPA imposes purchase requirements for alternate fuel vehicles for federal, state, municipal and private fleets which increase over a period of years. The Company expects these requirements for alternate fuel vehicles to develop business opportunities for the sale of compressed natural gas as fuel for vehicles, but it cannot predict the extent of this new market.
Gas Cost and Supply
Pipeline Corporation purchases natural gas under contracts with producers, brokers and interstate pipelines. The gas is brought to South Carolina through contracts with both Southern Natural and Transco. The volume of gas which Pipeline Corporation is entitled to transport through these contracts on a firm basis is shown below:
Maximum Daily Supplier Contract Demand Capacity (MCF)
Southern Natural Firm Transportation 160,000 Transco Firm Transportation 29,900 Total 189,900
Under a contract with Pipeline Corporation, the Company's maximum daily contract demand is 184,000 MCF. 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 $3.81 in 1993 compared to $3.65 in 1992.
To meet the requirements of the Company and its high priority natural gas customers during periods of maximum demand, Pipeline Corporation supplements its supplies of natural gas from two LNG plants. The LNG storage tanks are capable of storing the liquefied equivalent of 1,900,000 MCF of natural gas, of which approximately 1,450,000 MCF were in storage at December 31, 1993. On peak days the LNG plants can regasify up to 150,000 MCF per day. Additionally, Pipeline Corporation had contracted for 6,398,035 MCF of natural gas storage space on December 31, 1993, of which 4,880,484 MCF were in storage at such date. Propane air peak shaving facilities located in the Company's service area can supply an additional 137,400 MCF per day.
The Company believes that Pipeline Corporation's current supplies under contract and spot market purchase of natural gas are adequate to meet existing customer demands for service and to accommodate growth.
Curtailment Plans
The FERC has established allocation priorities applicable to firm and interruptible capacities on interstate pipeline companies to their customers 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 regulatory jurisdiction 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.
National Energy Policy Act of 1992
Congress has passed NEPA, the principal thrust of which is to create a more competitive wholesale power supply market by creating "exempt wholesale generators" (EWGs) designated by the FERC, which are independent power producers (IPPs) whose owners will not become holding companies under PUHCA. Upon application of a wholesaler of electric energy, the FERC may order an electric utility that owns transmission facilities used for wholesale sales of electric energy to provide transmission service (including any enlargement of transmission capacity needed to provide the service) to the applicant. Charges for transmission service must be "just and reasonable" and a utility is entitled to recover "all legitimate, verifiable economic costs" incurred in connection with any transmission service so ordered. The FERC may not order such service where it (1) would "unreasonably impair the continued reliability of electric wheeling" judged by reference to "consistently applied regional or national reliability standards, guidelines or criteria;" (2) would result in "retail wheeling;" or (3) would conflict with state laws governing retail marketing areas of electric utilities. Electric utilities, including exempt and non-exempt holding companies, may own and operate EWGs subject to advance approval by state utility commissions, which are given access to books and records of the EWG and its affiliates to the extent that such a commission requires access to perform its regulatory duties. It allows both registered and exempt
utility holding companies to acquire interests in foreign utility companies engaged in the generation, transmission or distribution of electricity or the retail distribution of gas, where a state commission has certified that it has the ability to protect the utility's retail ratepayers against adverse investments in foreign utilities by affiliates of public utilities that such commissions regulate. State Commissions must consider rate making changes and other regulatory reform to ensure that electric utilities' investments in energy efficiency and demand side management programs are at least as profitable as investing in new generating capacity. FERC has issued a Notice of Proposed Rule Making to develop regulations under NEPA concerning EWGs and electric transmission service.
NEPA also has provisions concerning nuclear power, alternate fuel vehicles, minimum efficiency standards, integrated resource planning, demand side management incentives, a variety of energy research projects relating to environmental measures, electric and magnetic fields, hydroelectric projects, and global warming. It authorizes one step licensing for nuclear power plants and requires EPA to issue standards for the Yucca Mountain repository site for nuclear waste (see "Nuclear Fuel Disposal" under "Environmental Control Matters"). To reduce dependence on imported oil, NEPA imposes purchase requirements for alternate fuel vehicles for federal, state, municipal and private fleets which increase over a period of years (see "Gas Operations").
In the opinion of the Company, it will be able to meet successfully the challenges of an altered business climate for electric and gas utilities and natural gas businesses. Neither the application of NEPA or FERC Order No. 636 nor the development of an EWG industry, new markets and obligations for transmission services for wholesale sales of electricity, nor deregulated interstate natural gas markets is expected to have a material adverse impact on the results of its operations, its financial position or its business prospects.
Federal Energy Regulatory Commission
Pursuant to Section 204 of the Federal Power Act, the Company must obtain FERC authority to issue short-term indebtedness. The FERC has authorized the Company to issue up to $200 million of unsecured promissory notes or commercial paper with maturity dates of 12 months or less but not later than December 31, 1995.
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: Neal Shoals (5,000 KW capability) and Stevens Creek (9,000 KW capability) 1993; Columbia (10,000 KW capability) 2000; Saluda Project (206,000 KW capability) 2007; and Parr Shoals (14,000 KW capability) and Fairfield Pumped Storage Project (512,000 KW capability) 2020. Pursuant to the provisions of the Federal Power Act as amended by the Electric Consumers Protection Act of 1986, applications for new licenses were filed on December 30, 1991. No competing applications were filed. The Neal Shoals license application was accepted for filing by the FERC on September 30, 1992 and the Stevens Creek application was accepted September 15, 1993. FERC has issued Notices of Authorization for Continued Project Operation for both projects until FERC has acted on SCE&G's applications for new licenses. FERC has announced its intentions to perform a Multiple-project Environmental Assessment for Neal Shoals and a Multiple-project Environmental Impact Statement for Stevens Creek.
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 United States takes over a project or the FERC issues a license to another applicant, the original licensee shall be paid its net investment in the project (not to exceed fair value) plus severance damages.
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. The NRC conducts semiannual reviews that identify plants that have demonstrated an excellent level of safety performance. Summer Station was recognized in both 1993 reviews as one of the top nuclear plants in the country.
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.
*Reflects a rate reduction of $3.7 million on January 4, 1993 (see discussion below) and excludes impact of rate reduction of $7.7 million on January 3, 1990 which corresponds to $7.7 million reduction in cost-of-service resulting from NRC approval of extension of Summer Station's operating life to 40 years.
** As modified
On June 7, 1993 the PSC issued an order on the Company's pending electric rate proceeding allowing an authorized return on common equity of 11.5%, resulting in a 7.4% annual increase in retail electric rates, or a projected $60.5 million annually based on a test year. These rates are to be implemented in two phases over a two-year period: phase one, effective June 1993, producing $42.0 million annually, and phase two, effective June 1994, producing $18.5 million annually, based on a test year. The Company's request, as modified, had proposed a return on equity of 12.05% and had projected annual increases of $53.0 million and $19.0 million for phases one and two, respectively.
On September 14, 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 on October 5, 1992. The Company has appealed the PSC's order to the Circuit Court. During oral arguments in February 1994 the Circuit Court retained jurisdiction and remanded the decision to the PSC for the limited purpose of answering questions concerning the applicable regulatory principles used by the PSC in determining these transit rates.
Since November 1, 1991 the Company's gas rate schedules for its residential, small commercial and small industrial customers have included a weather normalization adjustment (WNA). The WNA minimizes fluctuations in gas revenues due to abnormal weather conditions and has been approved through November 1994 subject to an annual review by the PSC. The PSC order was based on a return on common equity of 12.25%. The WNA became effective the first billing cycle in December 1991.
In May 1989 the PSC approved a volumetric and direct billing method for Pipeline Corporation to recover take-or-pay costs incurred from its interstate pipeline suppliers pursuant to FERC-approved final and non-appealable settlements. In December 1992 the Supreme Court approved Pipeline Corporation's full recovery of the take-or-pay charges imposed by its suppliers and treatment of these charges as a cost of gas. However, the Supreme Court declared the PSC-approved "purchase deficiency" methodology for recovery of these costs to be unlawful retroactive ratemaking and remanded the docket to the PSC to reconsider its recovery methodology. The Company believes that the elimination of the purchase deficiency method of recovery will affect the timing for recovery of take-or-pay charges and shift the allocations among Pipeline Corporation's customers (including the Company) but that all such charges should be ultimately recovered. The Supreme Court decision establishes a principle of law that will provide a basis for full recovery by the Company, as well as Pipeline Corporation, of these costs.
On July 3, 1989 the PSC granted the Company approximately $21.9 million of a requested $27.2 million annual increase in retail electric revenues based upon an allowed return on common equity of 13.25%. The Consumer Advocate appealed the decision to the Supreme Court which, on August 31, 1992, found that the evidence in the record of that case did not support a return on common equity higher than 13.0% and remanded to the PSC a portion of its July 1989 order for a determination of the proper return on common equity consistent with the Supreme Court's opinion. On January 19, 1993 the PSC issued an order allowing a return on common equity of 13.0%, approving a refund based on the difference in rates created by the difference between the 13.0% and the 13.25% return on common equity and making other non-material adjustments to the calculation of cost-of-service. The total refund before interest and income taxes, was approximately $14.6 million and was charged against 1992 "Electric Revenues." The refund plus interest was made during 1993.
On November 28, 1989 the PSC granted the Company an increase in firm retail natural gas rates, effective November 30, 1989, designed to increase annual revenues by $10.1 million, or 89.5% out of the requested increase of approximately $11.3 million. In its order the PSC authorized a 12.75% return on common equity. The Consumer Advocate appealed to the Supreme Court which on August 31, 1992 remanded the order to the PSC for redetermination of the proper amount of litigation expenses to include in the test period. In January 1993 the PSC reduced the amount of litigation expense and ordered a refund totaling approximately $163,000 which was charged against 1992 "Gas Revenues." The refund was made during 1993.
Fuel Cost Recovery Procedures
The PSC has established a fuel recovery procedure which determines the fuel component in the Company's retail electric base rates semiannually based on projected fuel costs for the ensuing six-month period, adjusted for any overcollection or undercollection from the preceding six-month period. The Company has the right to request a formal proceeding at any time should circumstances dictate such a review.
In the April 1993 semiannual review of the fuel cost component of electric rates, the PSC voted to reduce the rate from 13.5 mills per KWH to 13.0 mills per KWH, a monthly decrease of $.50 for an average customer using 1,000 KWH a month. This reduction coincided with the retail electric rate case effective June 1993. For the October 1993 review the PSC voted to continue the rate of 13.0 mills per KWH.
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 1993 review the PSC authorized an increase in the base cost of gas from 41.963 cents per therm to 47.100 cents per therm which resulted in a monthly increase of $5.14 (including applicable taxes) based on an average of 100 therms per month on a residential bill during the heating season.
In July 1990 the PSC initiated proceedings for a generic hearing on the Industrial Sales Program Rider (ISPR) for the Company and Pipeline Corporation. The PSC issued an order dated December 20, 1991 approving a Stipulation and Agreement signed in December 1991 by all parties involved which retained the ISPR with modifications to Pipeline Corporation's gas cost mechanisms.
ENVIRONMENTAL CONTROL MATTERS
General
Federal and state authorities have imposed environmental control requirements relating primarily to air emissions, wastewater discharges and solid, toxic and hazardous waste management. The Company is attempting to ensure that its operations meet applicable environmental regulations and standards. It is difficult to forecast the ultimate effect of environmental quality regulations upon the existing and proposed operations. Moreover, developments in these and other areas may require that equipment and facilities be modified, supplemented or replaced.
Capital Expenditures
In the years 1991 through 1993, capital expenditures for environmental control amounted to approximately $73.6 million. In addition, approximately $7.4 million, $5.7 million and $4.8 million of environmental control expenditures were made during 1993, 1992 and 1991, respectively, which were included in "Other operation" and "Maintenance" expenses. It is not possible to estimate all future costs for environmental purposes, but forecasts for minimum capitalized expenditures are $40.3 million for 1994 and $252.1 million for the four-year period 1995 through 1998. These expenditures are included in the Company's construction program.
Air Quality Control
The Federal Clean Air Act of 1970 (the "1970 Act") requires that electric generating plants comply with primary and secondary ambient air quality standards with respect to certain air pollutants including particulates, sulfur oxides and nitrogen oxides and imposes economic penalties for noncompliance. This Act was amended with the passage of the Clean Air Act Amendments of 1990.
Currently, the Company uses a variety of methods to comply with the State Implementation Plan (developed pursuant to the 1970 Act), including the use of low sulfur fuel, fuel switching, reduction of load during periods when compliance cannot be met at full power, maintenance and improvement of existing electrostatic precipitators and the installation of new baghouses. The Company and GENCO have been able to purchase sufficient fuel meeting current sulfur standards for all of their plants. With respect to sulfur dioxide emissions, none of the Company's electric generating plants is included among the Phase I plants listed in the Clean Air Act Amendments of 1990 with a compliance date of January 1, 1995. Both companies will, however, be affected by Phase II requirements which have a compliance date of January 1, 2000. The companies undertook a study in 1992 to determine the most cost effective mix of control options to meet the requirements of the Clean Air Act. Such a control strategy will most likely result in requiring the Company to utilize a combination of the following alternatives to meet its compliance requirements: (1) burn lower sulfur coal, (2) burn natural gas, (3) retrofit at least one coal-fired electric generating unit with a scrubber to remove sulfur dioxide and (4) purchase sulfur dioxide emission allowances to the extent necessary. In addition, the Company will install on most of its coal-fired units low nitrogen oxide burners to reduce nitrogen oxide emissions.
The Company currently estimates that, excluding GENCO, air emissions control equipment will require capital expenditures of $190 million over the 1994-1998 period to retrofit existing facilities and an increased operation and maintenance cost of $22 million per year. Total capital expenditures required to meet compliance requirements through the year 2003 are anticipated to be approximately $211 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 generating units. Commensurate with renewal of these permits has been implementation of a more rigorous control program on behalf of the permitting agency. The facilities have been developing compliance plans to meet the additional parameters of control and compliance has involved updating wastewater treatment technologies. Amendments to the Clean Water Act proposed recently in Congress include several provisions which could prove costly to the Company. These include limitations to mixing zones and the implementation of technology- based standards.
Superfund Act and Environmental Assessment Program
As described in Note 1L of Notes to Consolidated Financial Statements, 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 significantly differ from the original estimates. Amounts estimated and accrued to date ($19.6 million) for site assessments and cleanup relate primarily to regulated operations; such amounts have been deferred and are being amortized and recovered through rates over a ten-year period. Estimates to date include, among other things, the costs estimated to be associated with the matters discussed in the following paragraphs.
The Company and SCANA each own two decommissioned manufactured gas plant sites which contain residues of by-product chemicals. The Company and SCANA have each maintained an active review of their respective sites to monitor the nature and extent of the residual contamination.
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 originally encompassed approximately 18 acres and included properties which were the locations for industrial operations, including a wood preserving (creosote) plant and one of the Company's decommissioned manufactured gas plants. The original scope of this investigation has been expanded to approximately 30 acres including adjacent properties owned by the National Park Service and the City of Charleston, and private properties. The site has not been placed on the National Priority List, but may be added before cleanup is initiated. The potentially responsible parties (PRP) 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 investigations process to be compressed significantly. The PRPs have negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study (RI/FS) and a corresponding Scope of Work. Actual field work began November 1, 1993 after final approval and authorization was granted by EPA. The Company is also working with the City of Charleston to investigate potential contamination from the manufactured gas plant at the city's aquarium site.
During 1993 the Company settled its obligations at the Yellow Water Road Superfund Site near Jacksonville, Florida, the Spencer Transformer and Equipment Site in West Virginia and Elliott's Auto Parts in Benton, Arkansas. No further expenses are anticipated for these sites.
The Company has been listed as a PRP and has recorded liabilities, which are not considered material, for the Macon- Dockery waste disposal site near Rockingham, North Carolina, the Aqua-Tech Environmental, Inc. site in Greer, South Carolina and a landfill owned by Lexington County in South Carolina.
Solid Waste Control
The South Carolina Solid Waste Policy and Management Act of 1991 requires promulgation of regulations addressing specified subjects, one of which affects the management of industrial solid waste. This regulation will establish minimum criteria for industrial landfills as mandated under the Act. The proposed regulation, if adopted as a final regulation in its present form, could significantly impact the Company's engineering, design and operation of existing and future ash management facilities. Potential cost impacts could be substantial.
Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 (the "1982 Act") requires that the Federal Government make available by 1998 a permanent repository for high-level radioactive waste and spent nuclear fuel and imposes a fee of 1.0 mill 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 fuel storage capability until at least 2008 and expects to be able to expand its storage capacity over the life of Summer Station 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.
The 1982 Act also imposes on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. (See "Fuel Supply" under "Electric Operations" for a discussion of spent fuel storage facilities at Summer Station.)
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
Reference is made to Schedule V - Property Plant and Equipment, pages 54 through 59, for information concerning investments in utility plant and nonutility property. 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 590,000
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 Canadys Gas/Oil Canadys, SC 1968 14,000 Urquhart Gas/Oil Beech Island, SC 1969 26,000 Coit Gas/Oil Columbia, SC 1969 30,000 Parr (3) Gas/Oil Parr, SC 1970 60,000 Williams (4) 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 (5) 3,304,000
(1) Summer rating. (2) Represents the Company's two-thirds portion of the Summer Station. (3) Two of the four Parr gas turbines are leased and have a net capability of 34,000 KW. This lease expires on June 29, 1996. (4) The two gas turbines at Williams are leased and have a net capability of 49,000 KW. This lease expires on June 29, 1997. (5) Excludes Williams Station.
The Company owns 424 substations having an aggregate transformer capacity of 18,624,780 KVA. The transmission system consists of 3,033 miles of lines and the distribution system consists of 15,186 pole miles of overhead lines and 3,006 trench miles of underground lines.
GAS
Natural Gas The Company's gas system consists of approximately 6,179 miles of three-inch equivalent distribution pipelines and approximately 10,085 miles of distribution mains and related service facilities.
The gas system acquired by SCANA is operated by the Company and consists of approximately 450 miles of three-inch equivalent distribution pipelines and approximately 778 miles of distribution mains and related service facilities. Effective January 1, 1994 the assets and liabilities of such gas system were transferred from SCANA to the Company.
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.
TRANSIT
The Company owns 93 motor coaches which operate on a route system of 285 miles.
ITEM 3.

ITEM 3. LEGAL PROCEEDINGS
For information regarding legal proceedings, see ITEM 1., "BUSINESS," 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 STOCK AND RELATED SECURITY HOLDER MATTERS
All of the Company's common stock is owned by SCANA and therefore there is no market for such stock. During 1993 and 1992 the Company paid $108.6 million and $96.6 million, respectively, in cash dividends to SCANA.
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, 1993 approximately $10.6 million of retained earnings were restricted as to payment of cash dividends on common stock.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
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 investment, as well as to expand to meet future demands 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 based on historical costs. As customer growth and inflation occur and the Company expands its 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 relief.
Due to continuing customer growth, the Company entered into a contract with Duke/Fluor Daniel in 1991 to design, engineer and build a 385 MW coal-fired electric generating plant near Cope, South Carolina in Orangeburg County. Construction of the plant began in November 1992 with commercial operation expected in late 1995 or early 1996. The estimated price of the Cope plant, excluding financing costs and AFC but including an allowance for escalation, is $450 million. In addition, the transmission lines for interconnection with the Company's system are expected to cost $26 million. Until the completion of the new plant, the Company is contracting for additional capacity as necessary to ensure that the energy demands of its customers can be met.
As discussed in Note 2A of Notes to Consolidated Financial Statements on June 7, 1993 the PSC issued an order granting the Company a 7.4% annual increase in retail electric rates to be implemented in two phases of $42.0 million annually effective June 1993 and $18.5 million annually effective June 1994.
The estimated primary cash requirements for 1994, excluding requirements for fuel liabilities and short-term borrowings, and the actual primary cash requirements for 1993 are as follows:
1994 1993 (Thousands of Dollars) Property additions and construction expenditures, excluding allowance for funds used during construction (AFC) $384,287 $280,910 Nuclear fuel expenditures 28,064 7,177 Maturing obligations, redemptions and sinking and purchase fund requirements 5,024 3,700 Total $417,375 $291,787
Approximately 20.0% of total cash requirements (excluding dividends) was provided from internal sources in 1993 as compared to 49.2% in 1992.
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 12 consecutive months out of the 15 months prior to the month of issuance is at least twice the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 1993 the Bond Ratio was 3.70. The issuance of additional Class A Bonds is restricted also to an additional principal amount equal to 60% of unfunded net property additions (which unfunded net property additions totaled approximately $219.9 million at December 31, 1993), Class A Bonds issued on the basis of retirements of Class A Bonds (which retirement credits totaled $10.9 million at December 31, 1993) and Class A Bonds issued on the basis of cash on deposit with the Trustee.
The Company has placed a new bond indenture (New Mortgage) dated April 1, 1993 on substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are expected to be 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 $157 million were available for such purpose as of December 31, 1993), 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 12 consecutive months out of the 18 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, 1993 the New Bond Ratio was 5.0.
On April 29, 1993 the Securities and Exchange Commission declared effective a registration statement for the issuance of up to $700 million of New Bonds. The following series, aggregating $600 million, have been issued under such registration statement:
On June 9, 1993, $100 million, 7 5/8% Series due June 1, 2023 to repay short-term borrowings in a like amount.
On July 1, 1993, $100 million, 6% Series due June 15, 2000, and $150 million, 7 1/8% Series due June 15, 2013, and on July 20, 1993, $150 million, 7 1/2% Series due June 15, 2023, to redeem, on July 20, 1993, $382,035,000 of First and Refunding Mortgage Bonds maturing between 1999 and 2017 and bearing interest at rates between 8% and 9 7/8% per annum.
On December 20, 1993, $100 million, 6 1/4% Series due December 15, 2003 to repay short-term borrowings in a like amount.
On June 1, 1993 the Company redeemed the following amounts of First and Refunding Mortgage Bonds: $35 million, 10 1/8% Series due 2009 and $13 million, 9 7/8% Series due 2009.
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; provided, however, that 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 FERC authority to issue short-term indebtedness. The FERC ha authorized the Company to issue up to $200 million of unsecured promissory notes or commercial paper with maturity dates of 12 months or less but not later than December 31, 1995.
The Company has $127.0 million authorized and unused lines of credit at December 31, 1993. In addition, the Company has a credit agreement for a maximum of $75 million to finance nuclear and fossil fuel inventories, with $38.2 million available at December 31, 1993.
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 12 consecutive months immediately preceding the month of issuance is 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, 1993 the Preferred Stock Ratio was 2.52.
The Company anticipates that its 1994 cash requirements of $417.4 million will be met primarily through internally generated funds (approximately 32% excluding dividends), the sales of additional securities, additional equity contributions from SCANA and the incurrence of additional short-term and long-term indebtedness. The timing and amount of such financing will depend upon market conditions and other factors. Actual 1994 expenditures may vary from the estimates set forth above due to factors such as inflation and economic conditions, regulation and legislation, rates of load growth, environmental protection standards and the cost and availability of capital.
The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements.
Environmental Matters
The Clean Air Act requires electric utilities to reduce substantially emissions of sulfur dioxide and nitrogen oxide by the year 2000. These requirements are being phased in over two periods. The first phase has a compliance date of January 1, 1995 and the second, January 1, 2000. The Company meets all requirements of Phase I and therefore will not have to implement changes until compliance with Phase II requirements is necessary. The Company then will most likely meet its compliance requirements through the burning of natural gas and/or lower sulfur coal, the addition of scrubbers to coal-fired generating units, and the purchase of sulfur dioxide emission allowances. Low nitrogen oxide burners will be installed to reduce nitrogen oxide emissions.
The Company is continuing to refine a detailed compliance plan that must be filed with the EPA by January 1, 1996. The Company currently estimates that, excluding GENCO, air emissions control equipment will require capital expenditures of $190 million over the 1994-1998 period to retrofit existing facilities and an increased operation and maintenance cost of $22 million per year. Total capital expenditures required to meet compliance requirements through the year 2003 are anticipated to be approximately $211 million.
The South Carolina Solid Waste Policy and Management Act of 1991 requires promulgation of regulations addressing specified subjects, one of which affects the management of industrial solid waste. This regulation will establish minimum criteria for industrial landfills as mandated under the Act. The proposed regulation, if adopted as a final regulation in its present form, could significantly impact the Company's engineering, design and operation of existing and future ash management facilities. Potential cost impacts could be substantial.
As described in Note 1L of Notes to Consolidated Financial Statements, 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 significantly differ from the original estimates. Amounts estimated and accrued to date ($19.6 million) for site assessments and cleanup of regulated operations have been deferred and are being amortized and recovered through rates over a ten year period. Estimates to date include, among other things, the costs estimated to be associated with the matters discussed in the following paragraphs.
The Company and SCANA each own two decommissioned manufactured gas plant sites which contain residues of by-product chemicals. The Company and SCANA have each maintained an active review of their respective sites to monitor the nature and extent of the residual contamination.
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 originally encompassed approximately 18 acres and included properties which were the locations for industrial operations, including a wood preserving (creosote) plant and one of the Company's decommissioned manufactured gas plants. The original scope of this investigation has been expanded to approximately 30 acres including adjacent properties owned by the National Park Service and the City of Charleston, and private properties. The site has not been placed on the National Priority List, but may be added before cleanup is initiated. The potentially responsible parties (PRP) 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 investigations process to be compressed significantly. The PRPs have negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study (RI/FS) and a corresponding Scope of Work. Actual field work began November 1, 1993 after final approval and authorization was granted by EPA. The Company is also working with the City of Charleston to investigate potential contamination from the manufactured gas plant at the city's aquarium site. During 1993 the Company settled its obligations at the Yellow Water Road Superfund Site near Jacksonville, Florida, the Spencer Transformer and Equipment Site in West Virginia and Elliott's Auto Parts in Benton, Arkansas. No further expenses are anticipated for these sites.
The Company has been listed as a PRP and has recorded liabilities, which are not considered material, for the Macon- Dockery waste disposal site near Rockingham, North Carolina, the Aqua-Tech Environmental, Inc. site in Greer, South Carolina and a landfill owned by Lexington County in South Carolina.
Litigation
In January 1994 the Company, acting on behalf of itself and the PSA (as co-owners of Summer Station), reached a settlement with Westinghouse Electric Corporation (Westinghouse) resolving a dispute involving steam generators provided by Westinghouse to Summer Station which are defective in design, workmanship and materials. Terms of the settlement are confidential by agreement of the parties and order of the court. The Company had filed an action in May 1990 against Westinghouse in the U. S. District Court for South Carolina; an order dismissing this suit was issued on January 12, 1994.
Regulatory Matters
On June 7, 1993 the PSC issued an order on the Company's pending electric rate proceeding allowing an authorized return on common equity of 11.5%, resulting in a 7.4% annual increase in retail electric rates, or a projected $60.5 million annually on a test year basis. These rates are to be implemented in two phases over a two-year period: phase one, effective June 1993, producing $42.0 million annually, and phase two, effective June 1994, producing $18.5 million annually, on a test year basis.
The Company's operations are likely to be impacted by NEPA and FERC Order 636. NEPA is designed to create a more competitive wholesale power supply market by creating "exempt wholesale generators" and allowing for the potential requirement that a utility owning transmission facilities provide transmission access to wholesalers. Order No. 636 is 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 will be able to meet successfully the challenges of these altered business climates.
Other
In November 1992 the Financial Accounting Standards Board issued Statement No. 112 "Employers' Accounting for Postemployment Benefits." The Statement, which is effective for calendar year 1994, establishes certain conditions for the recognition of costs of benefits to former employees after employment but before retirement. The Statement requires recognition of the obligation to provide postemployment benefits if such obligation is attributable to services previously rendered, the obligation relates to rights which vest, payment of the benefits is probable and the amount of such benefits can be reasonably estimated. The Company does not anticipate that application of this Statement will have a significant impact on results of operations or financial position.
RESULTS OF OPERATIONS
Overview
Net income and the percent increase (decrease) from the previous year for the years 1993, 1992 and 1991 were as follows:
1993 1992 1991
Net income $145,968 $102,163 $122,836 Percent increase (decrease) in net income 42.9% (16.8%) 1.7%
1993 Net income increased for 1993 primarily due to an increase in the electric margin which more than offset increases in other operating expenses.
1992 Net income for 1992 decreased from 1991 primarily due to the recording of an $11.1 million (after interest and income taxes) reserve against earnings related to the August 31, 1992 retail electric rate ruling from the South Carolina Supreme Court (see Note 2E of Notes to Consolidated Financial Statements) and as a result of increased non-fuel operating expenses and interest charges.
The Company's financial statements include AFC. AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. Both an equity and debt portion of AFC are included in nonoperating income as noncash items which have the effect of increasing reported net income. AFC represented approximately 5.6% of income before income taxes in 1993, 5.5% in 1992 and 3.7% in 1991.
Electric Operations
Electric sales margins for 1993, 1992 and 1991 were as follows:
1993 1992 1991 (Millions of Dollars)
Electric revenues $940.2 $844.5 $867.7 Provision for rate refunds .3 (14.6) - Net Electric operating revenues 940.5 829.9 867.7 Less: Fuel used in electric generation 164.2 161.7 160.6 Purchased power 111.1 80.4 102.1 Margin $665.2 $587.8 $605.0
1993 The increase in electric sales margin from 1992 to 1993 is primarily a result of increased residential and commercial KWH sales due to weather and customer growth, an increase in retail electric rates beginning in June 1993, and a $14.6 million reserve recorded in 1992 as discussed below.
1992 The 1992 electric sales margin decreased from 1991 primarily due to the recording of a $14.6 million reserve, before interest and income taxes, related to the August 31, 1992 ruling from the Supreme Court (see Note 2E of Notes to Consolidated Financial Statements) and a $1.9 million billing-related litigation settlement included in 1991 electric operating revenues.
Increases (decreases) in megawatt hour (MWH) sales volume by classes are presented in the following table: Increase (Decrease) From Prior Year Volume (MWH) Classification 1993 1992
Residential 494,874 2,380 Commercial 305,560 37,749 Industrial 203,178 49,248 Sale for Resale (excluding interchange) 59,611 12,945 Other 24,873 (3,116) Total territorial 1,088,096 99,206 Interchange 121,013 16,558 Total 1,209,109 115,764
Warmer weather and an increase in the number of electric customers contributed to an all-time peak demand record of 3,557 MW (including Williams Station) on July 29, 1993. The previous year's record of 3,380 MW was set on July 13, 1992.
Gas Operations
Gas sales margins for 1993, 1992 and 1991 were as follows:
1993 1992 1991 (Millions of Dollars)
Gas revenues $174.0 $160.8 $150.8 Less: Gas purchased for resale 107.7 95.8 93.2 Margin $ 66.3 $ 65.0 $ 57.6
1993 The 1993 gas sales margin increased from 1992 primarily as a result of increases in higher margin residential and regular commercial sales.
1992 The 1992 gas sales margin increased from 1991 primarily due to recoveries of $4.2 million allowed under a weather normalization adjustment, increases in residential usage due to unseasonably cool weather during May 1992, and increased transportation volumes.
Increases (decreases) in dekatherm (DT) sales volume by classes are presented in the following table:
Increase (Decrease) From Prior Year Volume (DT) Classification 1993 1992
Residential 723,356 1,303,673 Commercial (186,529) 22,188 Industrial 547,193 (424,657) Total 1,084,020 901,204
Other Operating Expenses and Taxes
Increases (decreases) in other operating expenses, including taxes, are presented in the following table:
Increase (Decrease) From Prior Year Classification 1993 1992 (Millions of Dollars)
Other operation and maintenance $ 8.1 $11.5 Depreciation and amortization 4.2 5.4 Income taxes 29.9 (17.2) Other taxes (.2) 4.7 Total $42.0 $ 4.4
1993 Other operation and maintenance expenses increased for 1993 primarily due to the implementation of Financial Accounting Standards Board Statement No. 106 (See Note 1J of Notes to Consolidated Financial Statements) pursuant to the June 1993 PSC electric rate order and the amortization of environmental expenses. The depreciation and amortization increase reflects additions to plant in service. The increase in income taxes corresponds to the increase in the corporate tax rate from 34% to 35% retroactive to January 1, 1993.
1992 Other operation and maintenance expenses increased for 1992 primarily due to increases in administrative and general expense, increase in nuclear regulatory fees, and nuclear and transmission system maintenance. The increase in depreciation and amortization expense reflects additions to plant in service. The decrease in income tax expense is primarily related to the tax impact of the rate refund (see Note 2E of Notes to Consolidated Financial Statements) and to other decreases in income. The increase in other taxes is primarily due to higher property taxes caused by property additions and increased millage rates. In addition to the above, other taxes increased due to increases in state license fees.
Interest Expense
1993 Interest expense, excluding the debt component of AFC, decreased approximately $1.8 million primarily due to the redemption of First and Refunding Mortgage Bonds and the issuance of First Mortgage Bonds at lower interest rates and the 1992 interest on the provision for rate refund which were partially offset by interest on an adjustment for the 1987-1988 income tax audit.
1992 Interest expense increased approximately $5.7 million in 1992 compared to 1991 due to the issuances of the $145 million and $155 million of First and Refunding Mortgage Bonds on July 24, 1991 and August 29, 1991, respectively, which more than offset the decreases in interest expense resulting from the repayment of debt and lower interest rates on remaining debt and interest of $3.1 million accrued on the provision for rate refund (see Note 2E of Notes to Consolidated Financial Statements).
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
Independent Auditor's Report....................................... 29
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1993 and 1992... 30
Consolidated Statements of Income and Retained Earnings for the years ended December 31, 1993, 1992 and 1991............. 32
Consolidated Statements of Cash Flows for the years ended December 31, 1993, 1992 and 1991............................. 33
Consolidated Statements of Capitalization as of December 31, 1993 and 1992................................... 34
Notes to Consolidated Financial Statements..................... 36
Supplemental Financial Statement Schedules:
Schedule V - Property, Plant and Equipment for the years ended December 31, 1993, 1992 and 1991................. 54
Schedule VI - Accumulated Depreciation and Amortization of Property, Plant and Equipment for the years ended December 31, 1993, 1992 and 1991....................... 57
Supplemental financial statement schedules other than those listed above 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 AUDITOR'S 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, 1993 and 1992 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, 1993. Our audits also included the financial statement schedules listed in the index on page 28. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules 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, 1993 and 1992 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
s/Deloitte & Touche DELOITTE & TOUCHE Columbia, South Carolina February 7, 1994
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 accompanying Consolidated Financial Statements include the accounts of the Company and South Carolina Fuel Company, Inc. (Fuel Company) (see Note 1M). Intercompany balances and transactions between the Company and Fuel Company 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 South Carolina Pipeline Corporation (Pipeline Corporation) and at December 31, 1993 and 1992 the Company had approximately $15.1 million and $15.2 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 South Carolina Generating Company, Inc. (GENCO), under a unit power sales agreement. At December 31, 1993 and 1992 the Company had approximately $7.5 million and $4.5 million, respectively, payable to GENCO for unit power purchases. Such unit power purchases, which are included in "Purchased power," amounted to approximately $98.1 million, $73.1 million and $92.3 million in 1993, 1992 and 1991, respectively.
Total interest income (based on market interest rates) associated with the Company's advances to affiliated companies was approximately $129,000, $231,000 and $141,000 in 1993, 1992 and 1991.
Included in "Other interest expense" for 1993, 1992 and 1991 is approximately $29,000, $16,000 and $830,000, respectively, relating to advances from affiliated companies. Intercompany interest is calculated at market rates.
B. 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 Public Service Commission of South Carolina (PSC).
C. 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 the 885 MW 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 $920.2 million and $916.0 million as of December 31, 1993 and 1992, respectively. Accumulated depreciation associated with the Company's share of Summer Station was approximately $285.3 million and $262.2 million as of December 31, 1993 and 1992, respectively. The Company's share of the direct expenses associated with operating Summer Station is included in "Other operation" and "Maintenance" expenses.
D. Allowance for Funds Used During Construction
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, as a component of construction cost, of 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 rates of 9.4%, 9.4% and 9.8% for 1993, 1992 and 1991, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process is capitalized at the actual interest amount.
E. Deferred Return on Plant Investment
Commencing July 1, 1987, as approved by a PSC order on that date, the Company ceased the deferral of carrying costs associated with 400 MW of electric generating capacity previously removed from rate base and began amortizing the accumulated deferred carrying costs on a straight-line basis over a ten-year period. Amortization of deferred carrying costs, included in "Depreciation and amortization," was approximately $4.2 million for each of 1993, 1992 and 1991.
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 component in retail electric rates. The fuel component contained in electric rates is established by the PSC during semiannual fuel cost hearings. Any difference between actual fuel cost and that contained in the fuel component is deferred and included when determining the fuel cost component during the next semiannual fuel cost hearing. At December 31, 1993 and 1992 the Company had overcollected through the electric fuel clause component approximately $9.2 million and $17.7 million, respectively, which are included in "Deferred Credits - Other."
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, 1993 and 1992 the Company had undercollected through the gas cost recovery procedure approximately $11.0 million and $5.7 million, respectively, which are included in "Deferred Debits - Other."
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 2.97%, 3.00%, and 2.97% for 1993, 1992 and 1991, 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 United States Department of Energy under a contract for disposal of spent nuclear fuel.
H. Nuclear Decommissioning
Decommissioning of Summer Station is presently projected to commence in the year 2022 when the operating license expires. The expenditures (on a before-tax basis) related to the Company's share of decommissioning activities are currently estimated (in 2022 dollars, assuming an annual 4.5% rate of inflation) to be approximately $545.3 million including partial reclamation costs. The Company is providing for its share of estimated decommissioning costs over the life of Summer Station. The Company collected through rates $2.5 million and $1.6 million in 1993 and 1992, respectively. The amounts collected are deposited in 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.
In addition, pursuant to the National Energy Policy Act passed by Congress in 1992, the Company has recorded a liability for its estimated share of amounts required by the U. S. Department of Energy for its decommissioning fund. SCE&G will recover the costs associated with this liability, totaling $4.6 million at December 31, 1993, through the fuel cost component of its rates; accordingly, these amounts have been deferred and are included in "Deferred Debits-Other" and "Long-Term Debt, Net."
I. Income Taxes
The Company is included in the consolidated Federal and State income tax returns filed by SCANA. Income taxes are allocated to the Company based on its contribution to consolidated taxable income.
The Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," effective January 1, 1993. Prior years' financial statements have not been restated. Deferred tax assets and liabilities were adjusted from the amounts recorded at December 31, 1992 under prior standards to the amounts required at January 1, 1993 under Statement No. 109 at currently enacted income tax rates. The adjustments were charged or credited to regulatory assets or liabilities if the Company expects to recover the resulting additional income tax expense from, or pass through the resulting reductions in income tax expense to, customers of the Company; otherwise they were charged or credited to income tax expense. The cumulative effect of adopting Statement No. 109 on retained earnings as of January 1, 1993, as well as the effect of adoption on net income for the year ended December 31, 1993, was not material. The combined effect of adopting Statement No. 109 and adjusting deferred tax assets and liabilities for the change in 1993 of the corporate Federal income tax rate from 34% to 35% resulted in balances of $97.0 million in regulatory assets (included in "Deferred Debits- Other") and $56.6 million in regulatory liabilities (included in "Deferred Credits-Other").
In accordance with Statement No. 109, deferred tax assets and liabilities are recorded for the tax effect of temporary differences between the book 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.
Prior to the adoption of Statement No. 109 on January 1, 1993, the Company recorded a deferred income tax provision on all material timing differences between the inclusion of items in pretax financial income and taxable income each year, except for those which were expected to be passed through to, or collected from, customers. Accumulated deferred income taxes were generally not adjusted for changes in enacted tax rates.
J. Pension Expense
The Company participates in SCANA's noncontributory defined benefit pension plan, which covers all permanent Company 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 pension costs accrued to the extent permitted by the applicable Federal income tax regulations as determined by an independent actuary.
Net periodic pension cost, as determined by an independent actuary, for the years ended December 31, 1993, 1992 and 1991 included the following components:
The change in the annual discount rate used to determine benefit obligations from 8.0% to 7.25% as of December 31, 1993 increased the projected benefit obligation and reduced the unrecognized net gain by approximately $4.1 million.
In addition to pension benefits, the Company provides certain health care and life insurance benefits to active and retired employees. On January 1, 1993 the Company adopted Statement No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions." This Statement requires that the cost of postretirement benefits other than pensions be accrued during the years the employees render the service necessary to be eligible for the applicable benefits. The Company previously expensed these benefits, which are primarily health care, as claims were incurred. The accumulated obligation for these benefits at January 1, 1993 was approximately $68 million (transition liability) and the annualized increase in expenses (net of payments to current retirees), including the amortization of the transition liability over approximately 20 years as provided for by the Statement, is approximately $4.7 million. In its June 1993 electric rate order (see Note 2A) the PSC approved the inclusion in rates of the portion of increased expenses related to electric operations. Such expenses had been deferred through May 31, 1993 pursuant to a December 10, 1992 accounting directive allowing deferral pending consideration of recovery in future rate proceedings. For the year ended December 31, 1993 the Company expensed approximately $4.3 million, net of payments to current retirees.
Net periodic postretirement benefit cost, as determined by an independent actuary for the year ended December 31, 1993 included the following components (thousands of dollars):
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, 1993 and the accumulated postretirement benefit obligation as of December 31, 1993 would be to increase such amounts by $60,000 and $1.7 million, respectively.
K. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
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 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 significantly differ from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations; such amounts have been deferred and are being amortized and recovered through rates over a ten-year period. Such amounts totaled $19.6 million and $18.3 million at December 31, 1993 and 1992, respectively, and are included in "Deferred Debits-Other."
M. Fuel Inventory
Nuclear fuel and fossil fuel inventories 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. Accordingly, such fuel inventories and fuel-related assets and liabilities are included in the Company's consolidated financial statements (see Note 4).
N. Postemployment Benefits
In November 1992 the Financial Accounting Standards Board issued Statement No. 112 "Employers' Accounting for Postemployment Benefits." The Statement, which is effective for calendar year 1994, establishes certain conditions for the recognition of costs of benefits to former employees after employment but before retirement. The Statement requires recognition of the obligation to provide postemployment benefits if such obligation is attributable to services previously rendered, the obligation relates to rights which vest, payment of the benefits is probable, and the amount of such benefits can be reasonably estimated. The Company does not anticipate that application of this Statement will have a significant impact on results of operations or financial position.
O. 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.
P. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the 1993 presentation.
2. RATE MATTERS:
A. On June 7, 1993 the PSC issued an order on the Company's pending electric rate proceeding allowing an authorized return on common equity of 11.5%, resulting in a 7.4% annual increase in retail electric rates, or a projected $60.5 million annually based on a test year. These rates are to be implemented in two phases over a two-year period: phase one, effective June 1993, producing $42.0 million annually, and phase two, effective June 1994, producing $18.5 million annually, based on a test year.
B. On September 14, 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 on October 5, 1992. The Company has appealed the PSC's order to the Circuit Court. During oral arguments in February 1994 the Circuit Court retained jurisdiction and remanded the decision to the PSC for the limited purpose of answering questions concerning the applicable regulatory principles used by the PSC in determining these transit rates.
C. Since November 1, 1991 the Company's gas rate schedules for its residential, small commercial and small industrial customers have included a weather normalization adjustment. The WNA minimizes fluctuations in gas revenues due to abnormal weather conditions and has been approved through November 1994 subject to an annual review by the PSC. The PSC order was based on a return on common equity of 12.25%. The PSC also approved the WNA for SCANA's directly owned natural gas distribution system which is operated by the Company. The WNA became effective the first billing cycle in December 1991.
D. In May 1989 the PSC approved a volumetric and direct billing method for Pipeline Corporation to recover take-or-pay costs incurred from its interstate pipeline suppliers pursuant to FERC-approved final and non-appealable settlements. In December 1992 the Supreme Court approved Pipeline Corporation's full recovery of the take-or-pay charges imposed by its suppliers and treatment of these charges as a cost of gas. However, the Supreme Court declared the PSC-approved "purchase deficiency" methodology for recovery of these costs to be unlawful retroactive ratemaking and remanded the docket to the PSC to reconsider its recovery methodology. The Company believes that the elimination of the purchase deficiency method of recovery will affect the timing for recovery of take-or-pay charges and shift the allocations among Pipeline Corporation's customers (including the Company) but that all such charges should be ultimately recovered. The Supreme Court decision establishes a principle of law that will provide a basis for full recovery by the Company, as well as Pipeline Corporation, of these costs.
E. On July 3, 1989 the PSC granted the Company approximately $21.9 million of a requested $27.2 million annual increase in retail electric revenues based upon an allowed return on common equity of 13.25%. The Consumer Advocate appealed the decision to the Supreme Court which, on August 31, 1992, found that the evidence in the record of that case did not support a return on common equity higher than 13.0% and remanded to the PSC a portion of its July 1989 order for a determination of the proper return on common equity consistent with the Supreme Court's opinion. On January 19, 1993 the PSC issued an order allowing a return on common equity of 13.0%, approving a refund based on the difference in rates created by the difference between the 13.0% and the 13.25% return on common equity and making other non- material adjustments to the calculation of cost-of-service. The total refund, before interest and income taxes, was approximately $14.6 million, and was charged against 1992 "Electric Revenues." The refund plus interest was made during 1993.
F. On November 28, 1989 the PSC granted the Company an increase in firm retail natural gas rates, effective November 30, 1989, designed to increase annual revenues by $10.1 million, or 89.5% out of the requested increase of approximately $11.3 million. In its order the PSC authorized a 12.75% return on common equity. The Consumer Advocate appealed to the Supreme Court which on August 31, 1992 remanded the order to the PSC for redetermination of the proper amount of litigation expenses to include in the test period. In January 1993 the PSC reduced the amount of litigation expense and ordered a refund totaling approximately $163,000 which was charged against 1992 "Gas Revenues." The refund was made during 1993.
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 1994 through 1998 are summarized as follows:
Year Amount Year Amount (Thousands of Dollars)
1994 $13,719 1997 $26,345 1995 28,943 1998 31,325 1996 64,146
Approximately $10.9 million of the current portion of long- term debt for 1993 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. During 1993 certain issues of the Company's First and Refunding Mortgage Bonds were redeemed and replaced with First Mortgage Bonds.
Pipeline Corporation's two principal gas suppliers have incurred liabilities to gas producers under take-or-pay provisions of gas supply contracts. The FERC has accepted filings allowing these pipeline suppliers to recover portions of such take-or-pay liabilities from their customers, including Pipeline Corporation, through volumetric surcharges in gas rates and through direct billings.
The Company's liability to Pipeline Corporation for its proportionate share of take-or-pay costs was approximately $1.6 million at December 31, 1993 which is included in Accounts Payable - Affiliated Companies. The Company is paying this amount plus interest (9.4%) to Pipeline Corporation over a five- year period which began June 1989. The Company recovers these costs from its customers through the purchased gas adjustment (PGA) provisions in its rates.
The Company's take-or-pay liability to Pipeline Corporation will likely be increased due to the Supreme Court decision dated December 14, 1992 (see Note 2D). The Company anticipates that any such increase will be recovered through the PGA.
Certain outstanding long-term debt of an affiliated company (approximately $35.9 million at December 31, 1993 and 1992 respectively) is guaranteed by the Company.
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 are financed through the issuance of short-term commercial paper. These short-term borrowings are supported by an irrevocable revolving credit agreement which expires July 31, 1996. Accordingly, the amounts outstanding have been included in long-term debt. The credit agreement provides for a maximum amount of $75 million that may be outstanding at any time.
Commercial paper outstanding totaled $36.8 million and $55.7 million at December 31, 1993 and 1992 at weighted average interest rates of 3.47% and 3.81%, respectively.
5. STOCKHOLDERS' INVESTMENT (Including Preferred Stock Not Subject to Purchase or Sinking Funds):
The changes in "Stockholders' Investment" (Including Preferred Stock Not Subject to Purchase or Sinking Funds) during 1993, 1992 and 1991 are summarized as follows:
Common Preferred Thousands Shares Shares of Dollars
Balance December 31, 1990 40,296,147 322,877 $847,400 Changes in Retained Earnings: Net Income 122,836 Cash Dividends Declared: Preferred Stock (at stated rates) (6,706) Common Stock (97,000) Other 2 Balance December 31, 1991 40,296,147 322,877 866,532 Changes in Retained Earnings: Net Income 102,163 Cash Dividends Declared: Preferred Stock (at stated rates) (6,474) Common Stock (99,291) Equity Contributions from Parent 126,838 Balance December 31, 1992 40,296,147 322,877 989,768 Changes in Retained Earnings: Net Income 145,968 Cash Dividends Declared: Preferred Stock (at stated rates) (6,217) Common Stock (110,300) Equity Contributions from Parent 58,142 Balance December 31, 1993 40,296,147 322,877 $1,077,361
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, 1993 approximately $10.6 million of retained earnings were restricted as to payment of cash dividends on common stock.
6. PREFERRED STOCK (Subject to Purchase or Sinking Funds):
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.
At any time when dividends have not been paid in full or declared and set apart for payment on all series of preferred stock, the Company may not redeem any shares of preferred stock (unless all shares of preferred stock then outstanding are redeemed) or purchase or otherwise acquire for value any shares of preferred stock except in accordance with an offer made to all holders of preferred stock. The Company may not redeem any shares of preferred stock (unless all shares of preferred stock then outstanding are redeemed) or purchase or otherwise acquire for value any shares of preferred stock (except out of monies set aside as purchase funds or sinking funds for one or more series of preferred stock) at any time when it is in default under the provisions of the purchase fund or sinking fund for any series of preferred stock.
The aggregate annual amounts of purchase fund or sinking fund requirements for preferred stock for the years 1994 through 1998 are summarized as follows:
Year Amount Year Amount (Thousands of Dollars)
1994 $2,504 1997 $2,440 1995 2,515 1998 2,440 1996 2,482
The changes in "Total Preferred Stock (Subject to Purchase or Sinking Funds)" during 1993, 1992 and 1991 are summarized as follows:
Number Thousands of Shares of Dollars
Balance December 31, 1990 1,050,201 $ 64,460 Shares Redeemed: $100 par value (628) (63) $50 par value (51,169) (2,559) Balance December 31, 1991 998,404 61,838 Shares Redeemed: $100 par value (6,098) (610) $50 par value (51,777) (2,589) Balance December 31, 1992 940,529 58,639 Shares Redeemed: $100 par value (7,374) (737) $50 par value (51,187) (2,558) Balance December 31, 1993 881,968 $ 55,344
7. INCOME TAXES:
Total income tax expense for 1993, 1992 and 1991 is as follows:
1993 1992 1991 (Thousands of Dollars) Current taxes: Federal $60,577 $62,147 $36,594 State 6,822 7,852 4,833 Total current taxes 67,399 69,999 41,427 Deferred taxes, net: Federal 12,197 (16,274) 25,212 State 4,387 (322) 4,469 Total deferred taxes 16,584 (16,596) 29,681 Investment tax credits: Amortization of amounts deferred (credit) (3,245) (3,245) (3,245) Total income tax expense $80,738 $50,158 $67,863
Total income taxes differ from amounts computed by applying the statutory Federal income tax rate of 35% for 1993 and 34% for 1992 and 1991 to pretax income as follows:
The Omnibus Budget Reconciliation Act was signed into law on August 10, 1993, increasing the corporate tax rate from 34% to 35% effective January 1, 1993. This impact of this change on the Company's financial position and results of operation was not material.
The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $471.8 million at December 31, 1993 determined in accordance with Statement No. 109 (see Note 1I) are as follows (thousands of dollars):
Deferred tax assets: Unamortized investment tax credits $ 52,310 Cycle billing 15,084 Nuclear operations expenses 4,908 Deferred compensation programs 5,265 Other postretirement benefits 1,631 Injuries and damages 724 Other 3,808 Total deferred tax assets 83,730 Deferred tax liabilities: Accelerated depreciation and amortization 526,540 Reacquired debt 7,574 Property taxes 6,068 Pension expense 6,266 Nuclear system maintenance 2,965 Early retirement programs 1,961 Nuclear decontamination fund 1,417 Other 2,732 Total deferred tax liabilities 555,523 Net deferred tax liability $471,793
"Total deferred taxes" charged (credited) to income tax expense result from timing differences in recognition of the following items:
1992 1991 (Thousands of Dollars)
Charged (credited) to expense: Accelerated depreciation and amortization $ (5) $22,053 Deferred fuel accounting (2,947) 461 Property taxes 493 1,608 Cycle billing (1,381) 3,608 Nuclear refueling accrual (4,430) 2,052 Electric rate refund (6,571) - Injuries and damages (1,377) - Other, net (378) (101) Total deferred taxes $(16,596) $29,681
The Internal Revenue Service has examined and closed consolidated Federal income tax returns of SCANA Corporation through 1989 and is currently examining SCANA's 1990 and 1991 Federal income tax returns. No adjustments are currently proposed by the examining agent. SCANA does not anticipate that any adjustments which might result from this examination will have a significant impact on the earnings 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, 1993 and 1992 are as follows:
The information presented herein is based on pertinent information available to the Company as of December 31, 1993 and 1992. 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, 1993, 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 for similar instruments, or for those instruments for which there are no quoted market prices available, fair values are based on net present value calculations. 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 lines of credit. Commercial paper borrowings are for 270 days or less. Details of lines of credit and short-term borrowings at December 31, 1993, 1992 and 1991 and for the years then ended are as follows:
1993 1992 1991 (Millions of dollars)
Authorized lines of credit at year end $127.0 $119.9 $121.7 Unused lines of credit at year-end $127.0 $119.9 $121.7 Short-term borrowings (including commercial paper) during the year: Maximum outstanding $126.0 $ 95.3 $130.4 Average outstanding $ 56.0 $ 40.9 $ 64.5 Weighted daily average interest rates: Bank loans 3.24% 3.49% 7.69% Commercial paper 3.13% 3.69% 6.31% Short-term borrowings outstanding at year-end: Commercial paper $ 1.0 $ - $ - Weighted average interest rate 3.50% - - Bank loans $ - $ - $ - Weighted average interest rate - - -
10. COMMITMENTS AND CONTINGENCIES:
A. Construction
The Company entered into a contract with Duke/Fluor Daniel in 1991 to design, engineer and build a 385 MW coal-fired electric generating plant near Cope, South Carolina in Orangeburg County. Construction of the plant began in November 1992 and commercial operation is expected in late 1995 or early 1996. The estimated price of the Cope plant, excluding financing costs and AFC but including an allowance for escalation, is $450 million. In addition, the transmission lines for interconnection with the Company's system are expected to cost $26 million.
Under the Duke/Fluor Daniel contract the Company must make specified monthly minimum payments. These minimum payments do not include amounts for inflation on a portion of the contract which is subject to escalation (approximately 34% of the total contract amount). The aggregate amount of such required minimum payments remaining at December 31, 1993 is as follows (in thousands):
1994 $168,152 1995 59,766 1996 5,603 Total $233,521
Through December 31, 1993 the Company paid $142.0 million under the contract.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with the Company's public liability for a nuclear incident, currently establishes the liability limit for third-party claims associated with any nuclear incident at $9.4 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 not exceed approxi- mately $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 $1.4 billion for any losses in excess of $500 million pursuant to existing primary coverages (with ANI) on Summer Station. The Company pays annual premiums and, in addition, could be assessed a retroactive premium not to exceed 7 1/2 times its annual premium in the event of property damage loss to any nuclear generating facilities covered by NEIL. Based on the current annual premium, this retroactive premium would not exceed approximately $8.1 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 materially adverse impact on the Company's financial position.
C. Litigation
In January 1994 the Company, acting on behalf of itself and the PSA (as co-owners of Summer Station), reached a settlement with Westinghouse Electric Corporation (Westinghouse) resolving a dispute involving steam generators provided by Westinghouse to Summer Station which are defective in design, workmanship and materials. Terms of the settlement are confidential by agreement of the parties and order of the court. The Company had filed an action in May 1990 against Westinghouse in the U. S. District Court for South Carolina; an order dismissing this suit was issued on January 12, 1994.
D. Environmental
As described in Note 1L, 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 significantly differ from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations; such amounts have been deferred and are being amortized and recovered through rates over a ten-year period.
11. SEGMENT OF BUSINESS INFORMATION:
Segment information at December 31, 1993, 1992 and 1991 and for the years then ended is as follows:
Electric Gas Transit Total (Thousands of Dollars) Operating revenues $940,547 $174,035 $ 3,851 $1,118,433 Operating expenses, excluding depreciation and amortization 639,808 148,349 9,737 797,894 Depreciation and amortization 91,142 9,903 175 101,220 Total operating expenses 730,950 158,252 9,912 899,114 Operating income (loss) $209,597 $ 15,783 $(6,061) 219,319
Add - Other income, net 6,585 Less - Interest charges 79,936 Net income $ 145,968
Capital expenditures: Identifiable $ 274,408 $ 11,674 $ 604 $ 286,686
Utilized for overall Company operations 13,934 Total $ 300,620
Identifiable assets at December 31, 1993: Utility plant, net $2,445,466 $178,464 $1,673 $2,625,603 Inventories 66,181 2,526 463 69,170 Total $2,511,647 $180,990 $2,136 2,694,773
Assets utilized for overall Company operations 495,166 Total assets $3,189,939
Electric Gas Transit Total (Thousands of Dollars) Operating revenues $ 829,938 $160,820 $ 3,623 $ 994,381 Operating expenses, excluding depreciation and amortization 572,234 133,611 9,205 715,050 Depreciation and amortization 87,367 9,534 163 97,064 Total operating expenses 659,601 143,145 9,368 812,114 Operating income (loss) $ 170,337 $ 17,675 $(5,745) 182,267
Add - Other income, net 3,006 Less - Interest charges 83,110 Net income $ 102,163
Capital expenditures: Identifiable $ 223,697 $ 10,409 $ 346 $ 234,452
Utilized for overall Company operations 8,877 Total $ 243,329
Identifiable assets at December 31, 1992: Utility plant, net $2,271,895 $177,309 $ 1,240 $2,450,444 Inventories 68,435 2,967 481 71,883 Total $2,340,330 $180,276 $ 1,721 2,522,327
Assets utilized for overall Company operations 368,626 Total assets $2,890,953
Electric Gas Transit Total (Thousands of Dollars) Operating revenues $ 867,685 $ 150,788 $ 3,869 $1,022,342 Operating expenses, excluding depreciation and amortization 596,466 128,529 9,023 734,018 Depreciation and amortization 82,503 8,969 146 91,618 Total operating expenses 678,969 137,498 9,169 825,636 Operating income (loss) $ 188,716 $ 13,290 $ (5,300) 196,706
Add - Other income, net 3,283 Less - Interest charges 77,153 Net income $ 122,836
Capital expenditures: Identifiable $ 191,218 $ 16,029 $ 89 $ 207,336
Utilized for overall Company operations 7,967 Total $ 215,303
Identifiable assets at December 31, 1991: Utility plant, net $2,154,221 $ 176,570 $ 1,073 $2,331,864 Inventories 69,316 2,553 476 72,345 Total $2,223,537 $ 179,123 $ 1,549 2,404,209
Assets utilized for overall Company operations 344,371 Total assets $2,748,580
12. SUPPLEMENTARY INCOME STATEMENT INFORMATION:
Maintenance expense (including repairs) and provision for depreciation and amortization of utility plant are shown separately in the accompanying consolidated statements of income, except for amounts charged to clearing and other accounts, which amounts are not significant. Advertising expenses are not material and there were no royalties. Taxes other than income taxes are as follows (amounts for nonutility operations are not significant):
December 31, 1993 1992 1991 (Thousands of Dollars)
State electric generation tax $ 4,056 $ 4,299 $ 3,638 General property taxes 47,624 47,320 44,567 Special state utility license 1,814 1,965 1,595 Federal social security taxes 8,534 8,113 7,463 State gross receipts tax 2,871 3,427 2,734 Other taxes 462 470 942 Total charged to operating expenses $65,361 $65,594 $60,939
13. QUARTERLY FINANCIAL DATA (UNAUDITED):
(Thousands of Dollars) First Second Third Fourth Quarter Quarter Quarter Quarter Annual Total operating revenues $279,241 $244,485 $329,673 $265,034 $1,118,433 Operating income 55,274 38,934 79,363 45,748 219,319 Net Income 36,820 21,327 61,032 26,789 145,968
(Thousands of Dollars) First Second Third Fourth Quarter Quarter Quarter Quarter Annual Total operating revenues $263,576 $222,097 $270,937 $237,771 $994,381 Operating income 49,805 33,452 58,149 40,861 182,267 Net Income 30,055 13,528 36,747 21,833 102,163
DESCRIPTION OF PLANS
Incentive Compensation
To bring total compensation of officers to market levels, the Company has two incentive plans:
Annual Performance Incentive Plan
SCANA has annual Performance Incentive Plans for officers of SCANA and its subsidiaries. The plans promote SCANA's pay-for-performance philosophy, as well as its goal of having a meaningful amount of executive pay "at-risk." Through these plans, financial incentives are provided in the form of annual cash bonuses that are paid only when corporate, business unit and individual goals are achieved.
Short-term incentive awards are targeted below the median of the market. Executives eligible for these plans are assigned threshold, target and maximum bonus levels as a percentage of salary level. Bonuses earned are based on the level of the preestablished goals achieved. Award payouts may increase to a maximum of 1.5 times target, if Company performance exceeds the goals established. Even if this were to occur, payouts would still be below the market median. Award payouts may decrease, generally to a minimum of one-half the target-level awards, if the Company's performance is below targeted goals. Awards earned based on the achievement of preestablished goals may nonetheless be decreased to zero (as was done in 1992), if the Management Development and Corporate Performance Committee (Performance Committee) in its discretion determines that actual results do not warrant the levels of payouts otherwise earned.
The various plans in which officers of SCANA and its subsidiaries participate focus generally on short-term goals affecting profitability, efficiency, quality of service, customer satisfaction and progress toward SCANA's strategic objectives for the Company and its other subsidiaries. New performance categories for officers in the various plans are established annually. Specific performance measures, and their weights, also vary from year to year.
For 1993, the specific measures in each plan, and their weights, for the officers included in the Summary Compensation Table on page 66 are described below. The relationship of performance to payouts for the officers in each plan also is discussed.
For officers of SCANA, 80% of the total award is based on corporate Earnings Per Share ("EPS") goals. The remaining 20% is tied to the achievement of individual performance goals, and is awarded on a discretionary basis.
Specific EPS goals are established that correspond to threshold, target and maximum payouts for the EPS portion of awards. For 1993, SCANA's EPS results were sufficient to result in maximum payouts for that portion of the awards. Individual performance for corporate officers also was determined to be sufficient to result in maximum -level payouts for that portion of the awards. Awards for officers of the Company are based on three performance categories: corporate EPS, numerous corporate and Strategic Business Unit (SBU) financial and productivity goals, and additional SBU strategic initiatives (i.e., activities that focus on improvements in existing operating procedures, quality of service and product, human resources matters, etc.). One-third of the total award is based on results in each performance category. Threshold, target and maximum performance levels are established for each category; payouts will vary based on the actual level of performance achieved.
For 1993, the overall Company performance in all three categories was such that payouts exceeded target-level awards, but were less than the maximum awards possible. Although results for the first two performance categories were above target performance levels, results in the strategic initiative category were below that level.
Long-Term Performance Share Plan
SCANA has a long-term Performance Share Plan for officers of SCANA and its subsidiaries. The long-term Performance Share Plan measures SCANA's Total Shareholder Return ("TSR") relative to a group of peer companies (PSP Peer Group) over a three-year period. The PSP Peer Group includes 97 electric and gas utilities, none of which have annual revenues of less than $100 million.
Total Shareholder Return is stock price increase over the three-year period, plus cash dividends paid during the period, divided by stock price as of the beginning of the period. Comparing SCANA's TSR to a large group of other utilities reflects SCANA's recognition that investors could have invested their funds in other utility companies. Comparing SCANA's TSR against the TSR of the PSP Peer Group measures how well SCANA did when compared to others operating in similar interest, tax, economic and regulatory environments.
Executives eligible to participate in the Performance Share Plan are assigned target award opportunities based primarily on their salary level. In determining award sizes, levels of responsibilities and competitive practices also are considered. Target awards are established at levels slightly below the median of the market and represent a significant portion of executives "at-risk" compensation. But, to provide additional incentive for executives, and to ensure that executives are only rewarded when shareholders gain, actual payouts may exceed the median of the market when performance is outstanding. For lesser performance, awards will be at or below the market median.
Payouts occur when SCANA's TSR is in the top two-thirds of the PSP Peer Group, and vary based on SCANA's ranking against the peer group. Executives earn target payouts at the 50th percentile of three-year performance. Maximum payouts will be made at 1.5 times target when SCANA's TSR is at or above the 75th percentile of the peer group. No payouts will be earned if performance is in the bottom one-third of the peer group. Awards are denominated in shares of SCANA Common Stock and may be paid in either stock or cash or a combination of the two.
For the three-year period from 1991 through 1993, SCANA's TSR was at the 79th percentile of the PSP Peer Group. This resulted in payouts in February 1994 at the maximum level possible.
The combination of the annual Incentive Plan and the Performance Share Plan provides an opportunity to bring a participant's compensation to market levels. The progressive payout formulas in both plans dictate that above-market pay can be earned only for better-than-average corporate financial performance, and that poor performance will result in below- market pay.
The following table shows the target awards made in 1993 for potential payment in 1996 under the long-term Performance Share Plan, and estimated future payouts under that plan at threshold, target and maximum levels.
Defined Contribution Plans
Under the Savings Plan, most of the Company's employees may contribute up to 15% of their eligible earnings. The Company matches each employee's contribution on a dollar-for-dollar basis up to a maximum of 6% of the participant's eligible earnings as limited by the Internal Revenue Code (IRC). Both Company and employee contributions are invested in SCANA's Common Stock.
In addition to the Savings Plan, SCANA has a Supplementary Voluntary Deferral Plan (the "Supplementary Plan") for certain highly compensated employees of the Company and other SCANA subsidiaries. The Supplementary Plan is designed to provide employees whose participation in the Savings Plan is limited by the IRC with the ability to contribute and receive matching contributions in the same percentage as employees generally. However, unlike the Savings Plan where actual shares of SCANA Common Stock are acquired, under the Supplementary Plan the deferred amounts and matches are only accounted for as though shares of common stock had been purchased.
Defined Benefit Plans
In addition to the qualified Retirement Plan for all employees, the Company has Supplemental Executive Retirement Plans ("SERP") for certain eligible employees, including officers. 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 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. 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, 1994 and are not subject to any deduction for Social Security or other offset amounts.
Pension Plan Table
Final Service Years Average Pay 15 20 25 30 35
$125,000 35,130 46,840 58,550 70,260 72,595 150,000 42,630 56,840 71,050 85,260 88,220 175,000 50,130 66,840 83,550 100,260 103,845 200,000 57,630 76,840 96,050 115,260 119,470 225,000 65,130 86,840 108,550 130,260 135,095 250,000 72,630 96,840 121,050 145,260 150,720 300,000 87,630 116,840 146,050 175,260 181,970 350,000 102,630 136,840 171,050 205,260 213,220 400,000 117,630 156,840 196,050 235,260 244,470 450,000 132,630 176,840 221,050 265,260 275,720 500,000 147,630 196,840 246,050 295,260 306,970
The compensation shown in Column (c) of the Summary Compensation Table for the individuals named therein is covered by the Retirement Plan and/or a SERP. Messrs. Gressette, Kenyon, Timmerman, Young and Stedman now have credited service under the Retirement Plan (or its equivalent under the SERP) of 31, 20, 15, 31 and 21 years, respectively.
The Company also has a Key Employee Retention Program (the "Key Employee Retention Program") covering officers and certain other executive employees that provides supplemental retirement and/or death benefits for participants. Under the program the Company will pay to each participant for 180 months, upon retirement at or after age 65, a monthly retirement benefit equal to 25% of the average monthly salary of the participant over his final 36 months of employment prior to age 65, or an optional death benefit payable to a participant's designated beneficiary monthly 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 above are participating in the Key Employee Retention Program. Estimated annual retirement benefits payable at age 65 based on projected eligible compensation (assuming increases of 4% per year) to the five executive officers named in the Summary Compensation Table are as follows: Mr. Gressette - $106,863; Mr. Kenyon - $126,347; Mr. Timmerman - $105,411; Mr. Young - $56,013; and Mr. Stedman - $66,729.
Life Insurance Plans
The Company offers its officers and certain other highly- compensated employees an option to choose whole life insurance (the "Whole Life Option") in lieu of the term life insurance provided employees generally. Under this plan, the employee becomes the owner of a policy with a death benefit of between $200,000 and $550,000 depending upon the salary grade of the employee.
Termination, Severance and Change of Control Arrangements
The Company has a Key Executive Severance Benefit Plan (the "Severance Plan") intended to assure the objective judgment of, and to retain the loyalties of, key executives when the Company is faced with a potential change in control or a change in control by providing a continuation of salary and benefits after a participant's employment is terminated by the Company during a potential change in control, after a change in control without just cause, disability, retirement or death or by the participant for good reason after a change in control. All of the executive officers named in the Summary Compensation Table except Mr. Gressette have been designated as participants in the Severance Plan.
When a potential change in control occurs, a participant is obligated to remain with the Company for six months unless his employment is terminated for disability or normal retirement or until a change in control occurs. Upon a change in control resulting in an officer's termination, the Severance Plan provides for guaranteed severance payments equal to three times the annual compensation of the officer plus payments under certain of the Company's incentive and retirement plans. The officer also would receive an additional amount (a "gross-up" payment) for any IRC Section 4999 excess tax or any such other similar tax applicable to the severance payments. In addition, for 36 months after termination, the officer would receive coverage for medical benefits and life insurance so as to provide the same level of benefits previously enjoyed under group plans or individual policy contracts or otherwise as determined by the Executive Committee of the Board of Directors. Such benefits however would be reduced to the extent that the participant receives similar benefits during the period from another employer.
In addition to the Severance Plan, in the event of a merger, consolidation or acquisition in which SCANA is not the surviving corporation, target awards under the Performance Share Plan will become immediately payable based on SCANA's shareholder return performance as of the end of the most recently completed calendar year for each performance period as to which the grant of target shares has occurred at least six months previously.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
There are no executive officer-director interlocks where an executive officer of the Company serves on the compensation committee of another company that has an executive officer serving on the Company's Board of Directors. Messrs. Hipp, McMaster, Rhodes and Warren are all members of the Long-Term Compensation Committee which administers the Performance Share Plan. Messrs. Hipp and Rhodes also are members of the Performance Committee which generally handles all other executive compensation matters. Mr. Warren was the Chief Executive Officer of the Company from April 23, 1986 until January 31, 1990. Information with respect to transactions with entities with which Messrs. Hipp, McMaster, Rhodes and Warren are connected are described below. Mr. Gressette, Chairman of the Board and Chief Executive Officer of the Company, is an ex-officio (i.e. nonvoting) member of the Performance Committee. The Performance Committee receives his input on compensation matters concerning executive compensation of other officers but the committee deliberates and makes its decisions without his participation.
Mr. Rhodes is the Chairman and Chief Executive Officer of Rhodes Oil Company, Inc. Purchases from Rhodes Oil Company, Inc. totaling $62,500 for fuel oil and gasoline were made during 1993 by the Company. It is anticipated that such purchases will continue in the future.
Mr. McMaster is the President and Manager of Winnsboro Petroleum Company. Purchases from Winnsboro Petroleum Company totaling $77,549 for fuel oil and gasoline were made during 1993 by the Company. It is anticipated that such purchases will continue in the future.
Mr. Hipp, is the President and Chief Executive Officer of The Liberty Corporation. Mr. Hipp and John A. Warren are Directors of The Liberty Corporation. During 1993 certain of the insurance policies purchased by the Company on the lives of employees were written by Liberty Life Insurance Company, a subsidiary of the Liberty Corporation, and it is expected that this relationship will continue in the future. The total amount paid during 1993 by the Company to Liberty Life Insurance Company was $538,905.
COMPENSATION OF DIRECTORS
Fees
All of the Directors of the Company are also Directors of SCANA. During 1993, directors who are not employees of SCANA or its subsidiaries were each paid $14,500 for services rendered, plus $1,500 for each Board meeting attended and $700 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 $150. The fee for attendance at a conference is $500. In addition, Directors are paid, as part of their compensation, travel, lodging and incidental expenses related to attendance at meetings and conferences. Directors who are employees of SCANA or its subsidiaries receive no compensation for serving as directors or attending meetings.
Deferral Plan
The Company has a plan pursuant to which directors may defer all or a portion of their fees for services rendered and meeting attendance. Interest is earned on the deferred amounts at a rate set by the Performance Committee. During 1993 and currently, the rate is set at the announced prime rate of The South Carolina National Bank. During 1993, the only director participating in the plan was Mr. Rhodes. Interest credited to Mr. Rhodes' deferral account during 1993 was $8,526.
Endowment Plan
Each director participates 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 nominated by the 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 of SCANA and 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 SCANA's commitment to quality higher education and is intended to enhance SCANA's ability to attract and retain qualified board members.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
All shares of the Company's Common Stock are held, beneficially and of record, by SCANA Corporation.
The table set forth below indicates as of March 10, 1994, the shares of SCANA's Common Stock beneficially owned by each continuing director and nominee, each of the executive officers named in the Summary Compensation Table on page 66, and the directors and 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 1,243 W. H. Hipp 1,400 W. B. Bookhart, Jr. 6,884 B. D. Kenyon 4,782 W. T. Cassels, Jr. 1,000 F. C. McMaster 10,288 H. M. Chapman 3,127 Henry Ponder 4,806 J. B. Edwards 2,217 J. B. Rhodes 3,434 E. T. Freeman 1,500 W. B. Timmerman 12,889 L. M. Gressette, Jr. 14,649 E. C. Wall, Jr. 7,000 B. A. Hagood 1,140 John A. Warren 50,823 J. H. Young 5,108 R. W. Stedman 6,474
All directors and executive officers as a group (18 persons) TOTAL 138,764 TOTAL PERCENT OF CLASS 0.3%
(1) Includes shares owned by close relatives, the beneficial ownership of which is disclaimed by the director or nominee, as follows: Mr. Amick - 240; Mr. Bookhart - 1,913; Mr. Chapman - 127; Mr. Gressette - 530; Mr. Hagood - 159; Mr. McMaster - 6,365; Mr. Warren - 7,160.
Includes shares purchased through December 31, 1993, but not thereafter, by the Trustee under the Savings Plan.
The information set forth above as to the security ownership 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 28.
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.
Reports on Form 8-K
The Company filed a report on Form 8-K on January 13, 1994 in response to Item 5, "Other Events" regarding the settlement with Westinghouse Electric Corporation of a lawsuit relating to the steam generators provided to the Company's Summer Station.
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/Bruce D. Kenyon (NAME AND TITLE) Bruce D. Kenyon, President and Chief Operating Officer DATE February 15, 1994
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/L. M. Gressette, Jr. (NAME AND TITLE) L. M. Gressette, Jr., Chairman of the Board and Chief Executive Officer and Director DATE February 15, 1994
(ii) Principal financial officer: BY (SIGNATURE) s/W. B. Timmerman (NAME AND TITLE) W. B. Timmerman, Chief Financial Officer DATE February 15, 1994
(iii) Principal accounting officer: BY (SIGNATURE) s/J. E. Addison (NAME AND TITLE) J. E. Addison, Controller DATE February 15, 1994
BY (SIGNATURE) s/B. L. Amick (NAME AND TITLE) B. L. Amick, Director DATE February 15, 1994
BY (SIGNATURE) s/W. B. Bookhart, Jr. (NAME AND TITLE) W. B. Bookhart, Jr., Director DATE February 15, 1994
BY (SIGNATURE) s/W. T. Cassels, Jr. (NAME AND TITLE) W. T. Cassels, Jr., Director DATE February 15, 1994
BY (SIGNATURE) s/H. M. Chapman (NAME AND TITLE) H. M. Chapman, Director DATE February 15, 1994
BY (SIGNATURE) s/J. B. Edwards (NAME AND TITLE) J. B. Edwards, Director DATE February 15, 1994
BY (SIGNATURE) s/E. T. Freeman (NAME AND TITLE) E. T. Freeman, Director DATE February 15, 1994
BY (SIGNATURE) s/B. A. Hagood (NAME AND TITLE) B. A. Hagood, Director DATE February 15, 1994
BY (SIGNATURE) s/W. Hayne Hipp (NAME AND TITLE) W. Hayne Hipp, Director DATE February 15, 1994
BY (SIGNATURE) s/F. C. McMaster (NAME AND TITLE) F. C. McMaster, Director DATE February 15, 1994
BY (SIGNATURE) s/Henry Ponder (NAME AND TITLE) Henry Ponder, Director DATE February 15, 1994
BY (SIGNATURE) s/J. B. Rhodes (NAME AND TITLE) J. B. Rhodes, Director DATE February 15, 1994
BY (SIGNATURE) s/E. C. Wall, Jr. (NAME AND TITLE) E. C. Wall, Jr., Director DATE February 15, 1994
BY (SIGNATURE) s/John A. Warren (NAME AND TITLE) John A. Warren, Director DATE February 15, 1994


ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
LIQUIDITY AND CAPITAL RESOURCES
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 investment, as well as to expand to meet future demands 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 based on historical costs. As customer growth and inflation occur and the Company expands its 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 relief.
Due to continuing customer growth, the Company entered into a contract with Duke/Fluor Daniel in 1991 to design, engineer and build a 385 MW coal-fired electric generating plant near Cope, South Carolina in Orangeburg County. Construction of the plant began in November 1992 with commercial operation expected in late 1995 or early 1996. The estimated price of the Cope plant, excluding financing costs and AFC but including an allowance for escalation, is $450 million. In addition, the transmission lines for interconnection with the Company's system are expected to cost $26 million. Until the completion of the new plant, the Company is contracting for additional capacity as necessary to ensure that the energy demands of its customers can be met.
As discussed in Note 2A of Notes to Consolidated Financial Statements on June 7, 1993 the PSC issued an order granting the Company a 7.4% annual increase in retail electric rates to be implemented in two phases of $42.0 million annually effective June 1993 and $18.5 million annually effective June 1994.
The estimated primary cash requirements for 1994, excluding requirements for fuel liabilities and short-term borrowings, and the actual primary cash requirements for 1993 are as follows:
1994 1993 (Thousands of Dollars) Property additions and construction expenditures, excluding allowance for funds used during construction (AFC) $384,287 $280,910 Nuclear fuel expenditures 28,064 7,177 Maturing obligations, redemptions and sinking and purchase fund requirements 5,024 3,700 Total $417,375 $291,787
Approximately 20.0% of total cash requirements (excluding dividends) was provided from internal sources in 1993 as compared to 49.2% in 1992.
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 12 consecutive months out of the 15 months prior to the month of issuance is at least twice the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 1993 the Bond Ratio was 3.70. The issuance of additional Class A Bonds is restricted also to an additional principal amount equal to 60% of unfunded net property additions (which unfunded net property additions totaled approximately $219.9 million at December 31, 1993), Class A Bonds issued on the basis of retirements of Class A Bonds (which retirement credits totaled $10.9 million at December 31, 1993) and Class A Bonds issued on the basis of cash on deposit with the Trustee.
The Company has placed a new bond indenture (New Mortgage) dated April 1, 1993 on substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are expected to be 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 $157 million were available for such purpose as of December 31, 1993), 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 12 consecutive months out of the 18 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, 1993 the New Bond Ratio was 5.0.
On April 29, 1993 the Securities and Exchange Commission declared effective a registration statement for the issuance of up to $700 million of New Bonds. The following series, aggregating $600 million, have been issued under such registration statement:
On June 9, 1993, $100 million, 7 5/8% Series due June 1, 2023 to repay short-term borrowings in a like amount.
On July 1, 1993, $100 million, 6% Series due June 15, 2000, and $150 million, 7 1/8% Series due June 15, 2013, and on July 20, 1993, $150 million, 7 1/2% Series due June 15, 2023, to redeem, on July 20, 1993, $382,035,000 of First and Refunding Mortgage Bonds maturing between 1999 and 2017 and bearing interest at rates between 8% and 9 7/8% per annum.
On December 20, 1993, $100 million, 6 1/4% Series due December 15, 2003 to repay short-term borrowings in a like amount.
On June 1, 1993 the Company redeemed the following amounts of First and Refunding Mortgage Bonds: $35 million, 10 1/8% Series due 2009 and $13 million, 9 7/8% Series due 2009.
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; provided, however, that 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 FERC authority to issue short-term indebtedness. The FERC ha authorized the Company to issue up to $200 million of unsecured promissory notes or commercial paper with maturity dates of 12 months or less but not later than December 31, 1995.
The Company has $127.0 million authorized and unused lines of credit at December 31, 1993. In addition, the Company has a credit agreement for a maximum of $75 million to finance nuclear and fossil fuel inventories, with $38.2 million available at December 31, 1993.
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 12 consecutive months immediately preceding the month of issuance is 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, 1993 the Preferred Stock Ratio was 2.52.
The Company anticipates that its 1994 cash requirements of $417.4 million will be met primarily through internally generated funds (approximately 32% excluding dividends), the sales of additional securities, additional equity contributions from SCANA and the incurrence of additional short-term and long-term indebtedness. The timing and amount of such financing will depend upon market conditions and other factors. Actual 1994 expenditures may vary from the estimates set forth above due to factors such as inflation and economic conditions, regulation and legislation, rates of load growth, environmental protection standards and the cost and availability of capital.
The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements.
Environmental Matters
The Clean Air Act requires electric utilities to reduce substantially emissions of sulfur dioxide and nitrogen oxide by the year 2000. These requirements are being phased in over two periods. The first phase has a compliance date of January 1, 1995 and the second, January 1, 2000. The Company meets all requirements of Phase I and therefore will not have to implement changes until compliance with Phase II requirements is necessary. The Company then will most likely meet its compliance requirements through the burning of natural gas and/or lower sulfur coal, the addition of scrubbers to coal-fired generating units, and the purchase of sulfur dioxide emission allowances. Low nitrogen oxide burners will be installed to reduce nitrogen oxide emissions.
The Company is continuing to refine a detailed compliance plan that must be filed with the EPA by January 1, 1996. The Company currently estimates that, excluding GENCO, air emissions control equipment will require capital expenditures of $190 million over the 1994-1998 period to retrofit existing facilities and an increased operation and maintenance cost of $22 million per year. Total capital expenditures required to meet compliance requirements through the year 2003 are anticipated to be approximately $211 million.
The South Carolina Solid Waste Policy and Management Act of 1991 requires promulgation of regulations addressing specified subjects, one of which affects the management of industrial solid waste. This regulation will establish minimum criteria for industrial landfills as mandated under the Act. The proposed regulation, if adopted as a final regulation in its present form, could significantly impact the Company's engineering, design and operation of existing and future ash management facilities. Potential cost impacts could be substantial.
As described in Note 1L of Notes to Consolidated Financial Statements, 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 significantly differ from the original estimates. Amounts estimated and accrued to date ($19.6 million) for site assessments and cleanup of regulated operations have been deferred and are being amortized and recovered through rates over a ten year period. Estimates to date include, among other things, the costs estimated to be associated with the matters discussed in the following paragraphs.
The Company and SCANA each own two decommissioned manufactured gas plant sites which contain residues of by-product chemicals. The Company and SCANA have each maintained an active review of their respective sites to monitor the nature and extent of the residual contamination.
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 originally encompassed approximately 18 acres and included properties which were the locations for industrial operations, including a wood preserving (creosote) plant and one of the Company's decommissioned manufactured gas plants. The original scope of this investigation has been expanded to approximately 30 acres including adjacent properties owned by the National Park Service and the City of Charleston, and private properties. The site has not been placed on the National Priority List, but may be added before cleanup is initiated. The potentially responsible parties (PRP) 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 investigations process to be compressed significantly. The PRPs have negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study (RI/FS) and a corresponding Scope of Work. Actual field work began November 1, 1993 after final approval and authorization was granted by EPA. The Company is also working with the City of Charleston to investigate potential contamination from the manufactured gas plant at the city's aquarium site. During 1993 the Company settled its obligations at the Yellow Water Road Superfund Site near Jacksonville, Florida, the Spencer Transformer and Equipment Site in West Virginia and Elliott's Auto Parts in Benton, Arkansas. No further expenses are anticipated for these sites.
The Company has been listed as a PRP and has recorded liabilities, which are not considered material, for the Macon- Dockery waste disposal site near Rockingham, North Carolina, the Aqua-Tech Environmental, Inc. site in Greer, South Carolina and a landfill owned by Lexington County in South Carolina.
Litigation
In January 1994 the Company, acting on behalf of itself and the PSA (as co-owners of Summer Station), reached a settlement with Westinghouse Electric Corporation (Westinghouse) resolving a dispute involving steam generators provided by Westinghouse to Summer Station which are defective in design, workmanship and materials. Terms of the settlement are confidential by agreement of the parties and order of the court. The Company had filed an action in May 1990 against Westinghouse in the U. S. District Court for South Carolina; an order dismissing this suit was issued on January 12, 1994.
Regulatory Matters
On June 7, 1993 the PSC issued an order on the Company's pending electric rate proceeding allowing an authorized return on common equity of 11.5%, resulting in a 7.4% annual increase in retail electric rates, or a projected $60.5 million annually on a test year basis. These rates are to be implemented in two phases over a two-year period: phase one, effective June 1993, producing $42.0 million annually, and phase two, effective June 1994, producing $18.5 million annually, on a test year basis.
The Company's operations are likely to be impacted by NEPA and FERC Order 636. NEPA is designed to create a more competitive wholesale power supply market by creating "exempt wholesale generators" and allowing for the potential requirement that a utility owning transmission facilities provide transmission access to wholesalers. Order No. 636 is 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 will be able to meet successfully the challenges of these altered business climates.
Other
In November 1992 the Financial Accounting Standards Board issued Statement No. 112 "Employers' Accounting for Postemployment Benefits." The Statement, which is effective for calendar year 1994, establishes certain conditions for the recognition of costs of benefits to former employees after employment but before retirement. The Statement requires recognition of the obligation to provide postemployment benefits if such obligation is attributable to services previously rendered, the obligation relates to rights which vest, payment of the benefits is probable and the amount of such benefits can be reasonably estimated. The Company does not anticipate that application of this Statement will have a significant impact on results of operations or financial position.
RESULTS OF OPERATIONS
Overview
Net income and the percent increase (decrease) from the previous year for the years 1993, 1992 and 1991 were as follows:
1993 1992 1991
Net income $145,968 $102,163 $122,836 Percent increase (decrease) in net income 42.9% (16.8%) 1.7%
1993 Net income increased for 1993 primarily due to an increase in the electric margin which more than offset increases in other operating expenses.
1992 Net income for 1992 decreased from 1991 primarily due to the recording of an $11.1 million (after interest and income taxes) reserve against earnings related to the August 31, 1992 retail electric rate ruling from the South Carolina Supreme Court (see Note 2E of Notes to Consolidated Financial Statements) and as a result of increased non-fuel operating expenses and interest charges.
The Company's financial statements include AFC. AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. Both an equity and debt portion of AFC are included in nonoperating income as noncash items which have the effect of increasing reported net income. AFC represented approximately 5.6% of income before income taxes in 1993, 5.5% in 1992 and 3.7% in 1991.
Electric Operations
Electric sales margins for 1993, 1992 and 1991 were as follows:
1993 1992 1991 (Millions of Dollars)
Electric revenues $940.2 $844.5 $867.7 Provision for rate refunds .3 (14.6) - Net Electric operating revenues 940.5 829.9 867.7 Less: Fuel used in electric generation 164.2 161.7 160.6 Purchased power 111.1 80.4 102.1 Margin $665.2 $587.8 $605.0
1993 The increase in electric sales margin from 1992 to 1993 is primarily a result of increased residential and commercial KWH sales due to weather and customer growth, an increase in retail electric rates beginning in June 1993, and a $14.6 million reserve recorded in 1992 as discussed below.
1992 The 1992 electric sales margin decreased from 1991 primarily due to the recording of a $14.6 million reserve, before interest and income taxes, related to the August 31, 1992 ruling from the Supreme Court (see Note 2E of Notes to Consolidated Financial Statements) and a $1.9 million billing-related litigation settlement included in 1991 electric operating revenues.
Increases (decreases) in megawatt hour (MWH) sales volume by classes are presented in the following table: Increase (Decrease) From Prior Year Volume (MWH) Classification 1993 1992
Residential 494,874 2,380 Commercial 305,560 37,749 Industrial 203,178 49,248 Sale for Resale (excluding interchange) 59,611 12,945 Other 24,873 (3,116) Total territorial 1,088,096 99,206 Interchange 121,013 16,558 Total 1,209,109 115,764
Warmer weather and an increase in the number of electric customers contributed to an all-time peak demand record of 3,557 MW (including Williams Station) on July 29, 1993. The previous year's record of 3,380 MW was set on July 13, 1992.
Gas Operations
Gas sales margins for 1993, 1992 and 1991 were as follows:
1993 1992 1991 (Millions of Dollars)
Gas revenues $174.0 $160.8 $150.8 Less: Gas purchased for resale 107.7 95.8 93.2 Margin $ 66.3 $ 65.0 $ 57.6
1993 The 1993 gas sales margin increased from 1992 primarily as a result of increases in higher margin residential and regular commercial sales.
1992 The 1992 gas sales margin increased from 1991 primarily due to recoveries of $4.2 million allowed under a weather normalization adjustment, increases in residential usage due to unseasonably cool weather during May 1992, and increased transportation volumes.
Increases (decreases) in dekatherm (DT) sales volume by classes are presented in the following table:
Increase (Decrease) From Prior Year Volume (DT) Classification 1993 1992
Residential 723,356 1,303,673 Commercial (186,529) 22,188 Industrial 547,193 (424,657) Total 1,084,020 901,204
Other Operating Expenses and Taxes
Increases (decreases) in other operating expenses, including taxes, are presented in the following table:
Increase (Decrease) From Prior Year Classification 1993 1992 (Millions of Dollars)
Other operation and maintenance $ 8.1 $11.5 Depreciation and amortization 4.2 5.4 Income taxes 29.9 (17.2) Other taxes (.2) 4.7 Total $42.0 $ 4.4
1993 Other operation and maintenance expenses increased for 1993 primarily due to the implementation of Financial Accounting Standards Board Statement No. 106 (See Note 1J of Notes to Consolidated Financial Statements) pursuant to the June 1993 PSC electric rate order and the amortization of environmental expenses. The depreciation and amortization increase reflects additions to plant in service. The increase in income taxes corresponds to the increase in the corporate tax rate from 34% to 35% retroactive to January 1, 1993.
1992 Other operation and maintenance expenses increased for 1992 primarily due to increases in administrative and general expense, increase in nuclear regulatory fees, and nuclear and transmission system maintenance. The increase in depreciation and amortization expense reflects additions to plant in service. The decrease in income tax expense is primarily related to the tax impact of the rate refund (see Note 2E of Notes to Consolidated Financial Statements) and to other decreases in income. The increase in other taxes is primarily due to higher property taxes caused by property additions and increased millage rates. In addition to the above, other taxes increased due to increases in state license fees.
Interest Expense
1993 Interest expense, excluding the debt component of AFC, decreased approximately $1.8 million primarily due to the redemption of First and Refunding Mortgage Bonds and the issuance of First Mortgage Bonds at lower interest rates and the 1992 interest on the provision for rate refund which were partially offset by interest on an adjustment for the 1987-1988 income tax audit.
1992 Interest expense increased approximately $5.7 million in 1992 compared to 1991 due to the issuances of the $145 million and $155 million of First and Refunding Mortgage Bonds on July 24, 1991 and August 29, 1991, respectively, which more than offset the decreases in interest expense resulting from the repayment of debt and lower interest rates on remaining debt and interest of $3.1 million accrued on the provision for rate refund (see Note 2E of Notes to Consolidated Financial Statements).
ITEM 8.


ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Page
Independent Auditor's Report....................................... 29
Consolidated Financial Statements:
Consolidated Balance Sheets as of December 31, 1993 and 1992... 30
Consolidated Statements of Income and Retained Earnings for the years ended December 31, 1993, 1992 and 1991............. 32
Consolidated Statements of Cash Flows for the years ended December 31, 1993, 1992 and 1991............................. 33
Consolidated Statements of Capitalization as of December 31, 1993 and 1992................................... 34
Notes to Consolidated Financial Statements..................... 36
Supplemental Financial Statement Schedules:
Schedule V - Property, Plant and Equipment for the years ended December 31, 1993, 1992 and 1991................. 54
Schedule VI - Accumulated Depreciation and Amortization of Property, Plant and Equipment for the years ended December 31, 1993, 1992 and 1991....................... 57
Supplemental financial statement schedules other than those listed above 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 AUDITOR'S 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, 1993 and 1992 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, 1993. Our audits also included the financial statement schedules listed in the index on page 28. These financial statements and financial statement schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements and financial statement schedules 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, 1993 and 1992 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1993 in conformity with generally accepted accounting principles. Also, in our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
s/Deloitte & Touche DELOITTE & TOUCHE Columbia, South Carolina February 7, 1994
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 accompanying Consolidated Financial Statements include the accounts of the Company and South Carolina Fuel Company, Inc. (Fuel Company) (see Note 1M). Intercompany balances and transactions between the Company and Fuel Company 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 South Carolina Pipeline Corporation (Pipeline Corporation) and at December 31, 1993 and 1992 the Company had approximately $15.1 million and $15.2 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 South Carolina Generating Company, Inc. (GENCO), under a unit power sales agreement. At December 31, 1993 and 1992 the Company had approximately $7.5 million and $4.5 million, respectively, payable to GENCO for unit power purchases. Such unit power purchases, which are included in "Purchased power," amounted to approximately $98.1 million, $73.1 million and $92.3 million in 1993, 1992 and 1991, respectively.
Total interest income (based on market interest rates) associated with the Company's advances to affiliated companies was approximately $129,000, $231,000 and $141,000 in 1993, 1992 and 1991.
Included in "Other interest expense" for 1993, 1992 and 1991 is approximately $29,000, $16,000 and $830,000, respectively, relating to advances from affiliated companies. Intercompany interest is calculated at market rates.
B. 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 Public Service Commission of South Carolina (PSC).
C. 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 the 885 MW 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 $920.2 million and $916.0 million as of December 31, 1993 and 1992, respectively. Accumulated depreciation associated with the Company's share of Summer Station was approximately $285.3 million and $262.2 million as of December 31, 1993 and 1992, respectively. The Company's share of the direct expenses associated with operating Summer Station is included in "Other operation" and "Maintenance" expenses.
D. Allowance for Funds Used During Construction
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, as a component of construction cost, of 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 rates of 9.4%, 9.4% and 9.8% for 1993, 1992 and 1991, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process is capitalized at the actual interest amount.
E. Deferred Return on Plant Investment
Commencing July 1, 1987, as approved by a PSC order on that date, the Company ceased the deferral of carrying costs associated with 400 MW of electric generating capacity previously removed from rate base and began amortizing the accumulated deferred carrying costs on a straight-line basis over a ten-year period. Amortization of deferred carrying costs, included in "Depreciation and amortization," was approximately $4.2 million for each of 1993, 1992 and 1991.
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 component in retail electric rates. The fuel component contained in electric rates is established by the PSC during semiannual fuel cost hearings. Any difference between actual fuel cost and that contained in the fuel component is deferred and included when determining the fuel cost component during the next semiannual fuel cost hearing. At December 31, 1993 and 1992 the Company had overcollected through the electric fuel clause component approximately $9.2 million and $17.7 million, respectively, which are included in "Deferred Credits - Other."
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, 1993 and 1992 the Company had undercollected through the gas cost recovery procedure approximately $11.0 million and $5.7 million, respectively, which are included in "Deferred Debits - Other."
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 2.97%, 3.00%, and 2.97% for 1993, 1992 and 1991, 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 United States Department of Energy under a contract for disposal of spent nuclear fuel.
H. Nuclear Decommissioning
Decommissioning of Summer Station is presently projected to commence in the year 2022 when the operating license expires. The expenditures (on a before-tax basis) related to the Company's share of decommissioning activities are currently estimated (in 2022 dollars, assuming an annual 4.5% rate of inflation) to be approximately $545.3 million including partial reclamation costs. The Company is providing for its share of estimated decommissioning costs over the life of Summer Station. The Company collected through rates $2.5 million and $1.6 million in 1993 and 1992, respectively. The amounts collected are deposited in 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.
In addition, pursuant to the National Energy Policy Act passed by Congress in 1992, the Company has recorded a liability for its estimated share of amounts required by the U. S. Department of Energy for its decommissioning fund. SCE&G will recover the costs associated with this liability, totaling $4.6 million at December 31, 1993, through the fuel cost component of its rates; accordingly, these amounts have been deferred and are included in "Deferred Debits-Other" and "Long-Term Debt, Net."
I. Income Taxes
The Company is included in the consolidated Federal and State income tax returns filed by SCANA. Income taxes are allocated to the Company based on its contribution to consolidated taxable income.
The Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," effective January 1, 1993. Prior years' financial statements have not been restated. Deferred tax assets and liabilities were adjusted from the amounts recorded at December 31, 1992 under prior standards to the amounts required at January 1, 1993 under Statement No. 109 at currently enacted income tax rates. The adjustments were charged or credited to regulatory assets or liabilities if the Company expects to recover the resulting additional income tax expense from, or pass through the resulting reductions in income tax expense to, customers of the Company; otherwise they were charged or credited to income tax expense. The cumulative effect of adopting Statement No. 109 on retained earnings as of January 1, 1993, as well as the effect of adoption on net income for the year ended December 31, 1993, was not material. The combined effect of adopting Statement No. 109 and adjusting deferred tax assets and liabilities for the change in 1993 of the corporate Federal income tax rate from 34% to 35% resulted in balances of $97.0 million in regulatory assets (included in "Deferred Debits- Other") and $56.6 million in regulatory liabilities (included in "Deferred Credits-Other").
In accordance with Statement No. 109, deferred tax assets and liabilities are recorded for the tax effect of temporary differences between the book 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.
Prior to the adoption of Statement No. 109 on January 1, 1993, the Company recorded a deferred income tax provision on all material timing differences between the inclusion of items in pretax financial income and taxable income each year, except for those which were expected to be passed through to, or collected from, customers. Accumulated deferred income taxes were generally not adjusted for changes in enacted tax rates.
J. Pension Expense
The Company participates in SCANA's noncontributory defined benefit pension plan, which covers all permanent Company 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 pension costs accrued to the extent permitted by the applicable Federal income tax regulations as determined by an independent actuary.
Net periodic pension cost, as determined by an independent actuary, for the years ended December 31, 1993, 1992 and 1991 included the following components:
The change in the annual discount rate used to determine benefit obligations from 8.0% to 7.25% as of December 31, 1993 increased the projected benefit obligation and reduced the unrecognized net gain by approximately $4.1 million.
In addition to pension benefits, the Company provides certain health care and life insurance benefits to active and retired employees. On January 1, 1993 the Company adopted Statement No. 106 "Employers' Accounting for Postretirement Benefits Other Than Pensions." This Statement requires that the cost of postretirement benefits other than pensions be accrued during the years the employees render the service necessary to be eligible for the applicable benefits. The Company previously expensed these benefits, which are primarily health care, as claims were incurred. The accumulated obligation for these benefits at January 1, 1993 was approximately $68 million (transition liability) and the annualized increase in expenses (net of payments to current retirees), including the amortization of the transition liability over approximately 20 years as provided for by the Statement, is approximately $4.7 million. In its June 1993 electric rate order (see Note 2A) the PSC approved the inclusion in rates of the portion of increased expenses related to electric operations. Such expenses had been deferred through May 31, 1993 pursuant to a December 10, 1992 accounting directive allowing deferral pending consideration of recovery in future rate proceedings. For the year ended December 31, 1993 the Company expensed approximately $4.3 million, net of payments to current retirees.
Net periodic postretirement benefit cost, as determined by an independent actuary for the year ended December 31, 1993 included the following components (thousands of dollars):
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, 1993 and the accumulated postretirement benefit obligation as of December 31, 1993 would be to increase such amounts by $60,000 and $1.7 million, respectively.
K. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt
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 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 significantly differ from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations; such amounts have been deferred and are being amortized and recovered through rates over a ten-year period. Such amounts totaled $19.6 million and $18.3 million at December 31, 1993 and 1992, respectively, and are included in "Deferred Debits-Other."
M. Fuel Inventory
Nuclear fuel and fossil fuel inventories 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. Accordingly, such fuel inventories and fuel-related assets and liabilities are included in the Company's consolidated financial statements (see Note 4).
N. Postemployment Benefits
In November 1992 the Financial Accounting Standards Board issued Statement No. 112 "Employers' Accounting for Postemployment Benefits." The Statement, which is effective for calendar year 1994, establishes certain conditions for the recognition of costs of benefits to former employees after employment but before retirement. The Statement requires recognition of the obligation to provide postemployment benefits if such obligation is attributable to services previously rendered, the obligation relates to rights which vest, payment of the benefits is probable, and the amount of such benefits can be reasonably estimated. The Company does not anticipate that application of this Statement will have a significant impact on results of operations or financial position.
O. 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.
P. Reclassifications
Certain amounts from prior periods have been reclassified to conform with the 1993 presentation.
2. RATE MATTERS:
A. On June 7, 1993 the PSC issued an order on the Company's pending electric rate proceeding allowing an authorized return on common equity of 11.5%, resulting in a 7.4% annual increase in retail electric rates, or a projected $60.5 million annually based on a test year. These rates are to be implemented in two phases over a two-year period: phase one, effective June 1993, producing $42.0 million annually, and phase two, effective June 1994, producing $18.5 million annually, based on a test year.
B. On September 14, 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 on October 5, 1992. The Company has appealed the PSC's order to the Circuit Court. During oral arguments in February 1994 the Circuit Court retained jurisdiction and remanded the decision to the PSC for the limited purpose of answering questions concerning the applicable regulatory principles used by the PSC in determining these transit rates.
C. Since November 1, 1991 the Company's gas rate schedules for its residential, small commercial and small industrial customers have included a weather normalization adjustment. The WNA minimizes fluctuations in gas revenues due to abnormal weather conditions and has been approved through November 1994 subject to an annual review by the PSC. The PSC order was based on a return on common equity of 12.25%. The PSC also approved the WNA for SCANA's directly owned natural gas distribution system which is operated by the Company. The WNA became effective the first billing cycle in December 1991.
D. In May 1989 the PSC approved a volumetric and direct billing method for Pipeline Corporation to recover take-or-pay costs incurred from its interstate pipeline suppliers pursuant to FERC-approved final and non-appealable settlements. In December 1992 the Supreme Court approved Pipeline Corporation's full recovery of the take-or-pay charges imposed by its suppliers and treatment of these charges as a cost of gas. However, the Supreme Court declared the PSC-approved "purchase deficiency" methodology for recovery of these costs to be unlawful retroactive ratemaking and remanded the docket to the PSC to reconsider its recovery methodology. The Company believes that the elimination of the purchase deficiency method of recovery will affect the timing for recovery of take-or-pay charges and shift the allocations among Pipeline Corporation's customers (including the Company) but that all such charges should be ultimately recovered. The Supreme Court decision establishes a principle of law that will provide a basis for full recovery by the Company, as well as Pipeline Corporation, of these costs.
E. On July 3, 1989 the PSC granted the Company approximately $21.9 million of a requested $27.2 million annual increase in retail electric revenues based upon an allowed return on common equity of 13.25%. The Consumer Advocate appealed the decision to the Supreme Court which, on August 31, 1992, found that the evidence in the record of that case did not support a return on common equity higher than 13.0% and remanded to the PSC a portion of its July 1989 order for a determination of the proper return on common equity consistent with the Supreme Court's opinion. On January 19, 1993 the PSC issued an order allowing a return on common equity of 13.0%, approving a refund based on the difference in rates created by the difference between the 13.0% and the 13.25% return on common equity and making other non- material adjustments to the calculation of cost-of-service. The total refund, before interest and income taxes, was approximately $14.6 million, and was charged against 1992 "Electric Revenues." The refund plus interest was made during 1993.
F. On November 28, 1989 the PSC granted the Company an increase in firm retail natural gas rates, effective November 30, 1989, designed to increase annual revenues by $10.1 million, or 89.5% out of the requested increase of approximately $11.3 million. In its order the PSC authorized a 12.75% return on common equity. The Consumer Advocate appealed to the Supreme Court which on August 31, 1992 remanded the order to the PSC for redetermination of the proper amount of litigation expenses to include in the test period. In January 1993 the PSC reduced the amount of litigation expense and ordered a refund totaling approximately $163,000 which was charged against 1992 "Gas Revenues." The refund was made during 1993.
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 1994 through 1998 are summarized as follows:
Year Amount Year Amount (Thousands of Dollars)
1994 $13,719 1997 $26,345 1995 28,943 1998 31,325 1996 64,146
Approximately $10.9 million of the current portion of long- term debt for 1993 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. During 1993 certain issues of the Company's First and Refunding Mortgage Bonds were redeemed and replaced with First Mortgage Bonds.
Pipeline Corporation's two principal gas suppliers have incurred liabilities to gas producers under take-or-pay provisions of gas supply contracts. The FERC has accepted filings allowing these pipeline suppliers to recover portions of such take-or-pay liabilities from their customers, including Pipeline Corporation, through volumetric surcharges in gas rates and through direct billings.
The Company's liability to Pipeline Corporation for its proportionate share of take-or-pay costs was approximately $1.6 million at December 31, 1993 which is included in Accounts Payable - Affiliated Companies. The Company is paying this amount plus interest (9.4%) to Pipeline Corporation over a five- year period which began June 1989. The Company recovers these costs from its customers through the purchased gas adjustment (PGA) provisions in its rates.
The Company's take-or-pay liability to Pipeline Corporation will likely be increased due to the Supreme Court decision dated December 14, 1992 (see Note 2D). The Company anticipates that any such increase will be recovered through the PGA.
Certain outstanding long-term debt of an affiliated company (approximately $35.9 million at December 31, 1993 and 1992 respectively) is guaranteed by the Company.
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 are financed through the issuance of short-term commercial paper. These short-term borrowings are supported by an irrevocable revolving credit agreement which expires July 31, 1996. Accordingly, the amounts outstanding have been included in long-term debt. The credit agreement provides for a maximum amount of $75 million that may be outstanding at any time.
Commercial paper outstanding totaled $36.8 million and $55.7 million at December 31, 1993 and 1992 at weighted average interest rates of 3.47% and 3.81%, respectively.
5. STOCKHOLDERS' INVESTMENT (Including Preferred Stock Not Subject to Purchase or Sinking Funds):
The changes in "Stockholders' Investment" (Including Preferred Stock Not Subject to Purchase or Sinking Funds) during 1993, 1992 and 1991 are summarized as follows:
Common Preferred Thousands Shares Shares of Dollars
Balance December 31, 1990 40,296,147 322,877 $847,400 Changes in Retained Earnings: Net Income 122,836 Cash Dividends Declared: Preferred Stock (at stated rates) (6,706) Common Stock (97,000) Other 2 Balance December 31, 1991 40,296,147 322,877 866,532 Changes in Retained Earnings: Net Income 102,163 Cash Dividends Declared: Preferred Stock (at stated rates) (6,474) Common Stock (99,291) Equity Contributions from Parent 126,838 Balance December 31, 1992 40,296,147 322,877 989,768 Changes in Retained Earnings: Net Income 145,968 Cash Dividends Declared: Preferred Stock (at stated rates) (6,217) Common Stock (110,300) Equity Contributions from Parent 58,142 Balance December 31, 1993 40,296,147 322,877 $1,077,361
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, 1993 approximately $10.6 million of retained earnings were restricted as to payment of cash dividends on common stock.
6. PREFERRED STOCK (Subject to Purchase or Sinking Funds):
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.
At any time when dividends have not been paid in full or declared and set apart for payment on all series of preferred stock, the Company may not redeem any shares of preferred stock (unless all shares of preferred stock then outstanding are redeemed) or purchase or otherwise acquire for value any shares of preferred stock except in accordance with an offer made to all holders of preferred stock. The Company may not redeem any shares of preferred stock (unless all shares of preferred stock then outstanding are redeemed) or purchase or otherwise acquire for value any shares of preferred stock (except out of monies set aside as purchase funds or sinking funds for one or more series of preferred stock) at any time when it is in default under the provisions of the purchase fund or sinking fund for any series of preferred stock.
The aggregate annual amounts of purchase fund or sinking fund requirements for preferred stock for the years 1994 through 1998 are summarized as follows:
Year Amount Year Amount (Thousands of Dollars)
1994 $2,504 1997 $2,440 1995 2,515 1998 2,440 1996 2,482
The changes in "Total Preferred Stock (Subject to Purchase or Sinking Funds)" during 1993, 1992 and 1991 are summarized as follows:
Number Thousands of Shares of Dollars
Balance December 31, 1990 1,050,201 $ 64,460 Shares Redeemed: $100 par value (628) (63) $50 par value (51,169) (2,559) Balance December 31, 1991 998,404 61,838 Shares Redeemed: $100 par value (6,098) (610) $50 par value (51,777) (2,589) Balance December 31, 1992 940,529 58,639 Shares Redeemed: $100 par value (7,374) (737) $50 par value (51,187) (2,558) Balance December 31, 1993 881,968 $ 55,344
7. INCOME TAXES:
Total income tax expense for 1993, 1992 and 1991 is as follows:
1993 1992 1991 (Thousands of Dollars) Current taxes: Federal $60,577 $62,147 $36,594 State 6,822 7,852 4,833 Total current taxes 67,399 69,999 41,427 Deferred taxes, net: Federal 12,197 (16,274) 25,212 State 4,387 (322) 4,469 Total deferred taxes 16,584 (16,596) 29,681 Investment tax credits: Amortization of amounts deferred (credit) (3,245) (3,245) (3,245) Total income tax expense $80,738 $50,158 $67,863
Total income taxes differ from amounts computed by applying the statutory Federal income tax rate of 35% for 1993 and 34% for 1992 and 1991 to pretax income as follows:
The Omnibus Budget Reconciliation Act was signed into law on August 10, 1993, increasing the corporate tax rate from 34% to 35% effective January 1, 1993. This impact of this change on the Company's financial position and results of operation was not material.
The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $471.8 million at December 31, 1993 determined in accordance with Statement No. 109 (see Note 1I) are as follows (thousands of dollars):
Deferred tax assets: Unamortized investment tax credits $ 52,310 Cycle billing 15,084 Nuclear operations expenses 4,908 Deferred compensation programs 5,265 Other postretirement benefits 1,631 Injuries and damages 724 Other 3,808 Total deferred tax assets 83,730 Deferred tax liabilities: Accelerated depreciation and amortization 526,540 Reacquired debt 7,574 Property taxes 6,068 Pension expense 6,266 Nuclear system maintenance 2,965 Early retirement programs 1,961 Nuclear decontamination fund 1,417 Other 2,732 Total deferred tax liabilities 555,523 Net deferred tax liability $471,793
"Total deferred taxes" charged (credited) to income tax expense result from timing differences in recognition of the following items:
1992 1991 (Thousands of Dollars)
Charged (credited) to expense: Accelerated depreciation and amortization $ (5) $22,053 Deferred fuel accounting (2,947) 461 Property taxes 493 1,608 Cycle billing (1,381) 3,608 Nuclear refueling accrual (4,430) 2,052 Electric rate refund (6,571) - Injuries and damages (1,377) - Other, net (378) (101) Total deferred taxes $(16,596) $29,681
The Internal Revenue Service has examined and closed consolidated Federal income tax returns of SCANA Corporation through 1989 and is currently examining SCANA's 1990 and 1991 Federal income tax returns. No adjustments are currently proposed by the examining agent. SCANA does not anticipate that any adjustments which might result from this examination will have a significant impact on the earnings 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, 1993 and 1992 are as follows:
The information presented herein is based on pertinent information available to the Company as of December 31, 1993 and 1992. 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, 1993, 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 for similar instruments, or for those instruments for which there are no quoted market prices available, fair values are based on net present value calculations. 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 lines of credit. Commercial paper borrowings are for 270 days or less. Details of lines of credit and short-term borrowings at December 31, 1993, 1992 and 1991 and for the years then ended are as follows:
1993 1992 1991 (Millions of dollars)
Authorized lines of credit at year end $127.0 $119.9 $121.7 Unused lines of credit at year-end $127.0 $119.9 $121.7 Short-term borrowings (including commercial paper) during the year: Maximum outstanding $126.0 $ 95.3 $130.4 Average outstanding $ 56.0 $ 40.9 $ 64.5 Weighted daily average interest rates: Bank loans 3.24% 3.49% 7.69% Commercial paper 3.13% 3.69% 6.31% Short-term borrowings outstanding at year-end: Commercial paper $ 1.0 $ - $ - Weighted average interest rate 3.50% - - Bank loans $ - $ - $ - Weighted average interest rate - - -
10. COMMITMENTS AND CONTINGENCIES:
A. Construction
The Company entered into a contract with Duke/Fluor Daniel in 1991 to design, engineer and build a 385 MW coal-fired electric generating plant near Cope, South Carolina in Orangeburg County. Construction of the plant began in November 1992 and commercial operation is expected in late 1995 or early 1996. The estimated price of the Cope plant, excluding financing costs and AFC but including an allowance for escalation, is $450 million. In addition, the transmission lines for interconnection with the Company's system are expected to cost $26 million.
Under the Duke/Fluor Daniel contract the Company must make specified monthly minimum payments. These minimum payments do not include amounts for inflation on a portion of the contract which is subject to escalation (approximately 34% of the total contract amount). The aggregate amount of such required minimum payments remaining at December 31, 1993 is as follows (in thousands):
1994 $168,152 1995 59,766 1996 5,603 Total $233,521
Through December 31, 1993 the Company paid $142.0 million under the contract.
B. Nuclear Insurance
The Price-Anderson Indemnification Act, which deals with the Company's public liability for a nuclear incident, currently establishes the liability limit for third-party claims associated with any nuclear incident at $9.4 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 not exceed approxi- mately $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 $1.4 billion for any losses in excess of $500 million pursuant to existing primary coverages (with ANI) on Summer Station. The Company pays annual premiums and, in addition, could be assessed a retroactive premium not to exceed 7 1/2 times its annual premium in the event of property damage loss to any nuclear generating facilities covered by NEIL. Based on the current annual premium, this retroactive premium would not exceed approximately $8.1 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 materially adverse impact on the Company's financial position.
C. Litigation
In January 1994 the Company, acting on behalf of itself and the PSA (as co-owners of Summer Station), reached a settlement with Westinghouse Electric Corporation (Westinghouse) resolving a dispute involving steam generators provided by Westinghouse to Summer Station which are defective in design, workmanship and materials. Terms of the settlement are confidential by agreement of the parties and order of the court. The Company had filed an action in May 1990 against Westinghouse in the U. S. District Court for South Carolina; an order dismissing this suit was issued on January 12, 1994.
D. Environmental
As described in Note 1L, 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 significantly differ from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations; such amounts have been deferred and are being amortized and recovered through rates over a ten-year period.
11. SEGMENT OF BUSINESS INFORMATION:
Segment information at December 31, 1993, 1992 and 1991 and for the years then ended is as follows:
Electric Gas Transit Total (Thousands of Dollars) Operating revenues $940,547 $174,035 $ 3,851 $1,118,433 Operating expenses, excluding depreciation and amortization 639,808 148,349 9,737 797,894 Depreciation and amortization 91,142 9,903 175 101,220 Total operating expenses 730,950 158,252 9,912 899,114 Operating income (loss) $209,597 $ 15,783 $(6,061) 219,319
Add - Other income, net 6,585 Less - Interest charges 79,936 Net income $ 145,968
Capital expenditures: Identifiable $ 274,408 $ 11,674 $ 604 $ 286,686
Utilized for overall Company operations 13,934 Total $ 300,620
Identifiable assets at December 31, 1993: Utility plant, net $2,445,466 $178,464 $1,673 $2,625,603 Inventories 66,181 2,526 463 69,170 Total $2,511,647 $180,990 $2,136 2,694,773
Assets utilized for overall Company operations 495,166 Total assets $3,189,939
Electric Gas Transit Total (Thousands of Dollars) Operating revenues $ 829,938 $160,820 $ 3,623 $ 994,381 Operating expenses, excluding depreciation and amortization 572,234 133,611 9,205 715,050 Depreciation and amortization 87,367 9,534 163 97,064 Total operating expenses 659,601 143,145 9,368 812,114 Operating income (loss) $ 170,337 $ 17,675 $(5,745) 182,267
Add - Other income, net 3,006 Less - Interest charges 83,110 Net income $ 102,163
Capital expenditures: Identifiable $ 223,697 $ 10,409 $ 346 $ 234,452
Utilized for overall Company operations 8,877 Total $ 243,329
Identifiable assets at December 31, 1992: Utility plant, net $2,271,895 $177,309 $ 1,240 $2,450,444 Inventories 68,435 2,967 481 71,883 Total $2,340,330 $180,276 $ 1,721 2,522,327
Assets utilized for overall Company operations 368,626 Total assets $2,890,953
Electric Gas Transit Total (Thousands of Dollars) Operating revenues $ 867,685 $ 150,788 $ 3,869 $1,022,342 Operating expenses, excluding depreciation and amortization 596,466 128,529 9,023 734,018 Depreciation and amortization 82,503 8,969 146 91,618 Total operating expenses 678,969 137,498 9,169 825,636 Operating income (loss) $ 188,716 $ 13,290 $ (5,300) 196,706
Add - Other income, net 3,283 Less - Interest charges 77,153 Net income $ 122,836
Capital expenditures: Identifiable $ 191,218 $ 16,029 $ 89 $ 207,336
Utilized for overall Company operations 7,967 Total $ 215,303
Identifiable assets at December 31, 1991: Utility plant, net $2,154,221 $ 176,570 $ 1,073 $2,331,864 Inventories 69,316 2,553 476 72,345 Total $2,223,537 $ 179,123 $ 1,549 2,404,209
Assets utilized for overall Company operations 344,371 Total assets $2,748,580
12. SUPPLEMENTARY INCOME STATEMENT INFORMATION:
Maintenance expense (including repairs) and provision for depreciation and amortization of utility plant are shown separately in the accompanying consolidated statements of income, except for amounts charged to clearing and other accounts, which amounts are not significant. Advertising expenses are not material and there were no royalties. Taxes other than income taxes are as follows (amounts for nonutility operations are not significant):
December 31, 1993 1992 1991 (Thousands of Dollars)
State electric generation tax $ 4,056 $ 4,299 $ 3,638 General property taxes 47,624 47,320 44,567 Special state utility license 1,814 1,965 1,595 Federal social security taxes 8,534 8,113 7,463 State gross receipts tax 2,871 3,427 2,734 Other taxes 462 470 942 Total charged to operating expenses $65,361 $65,594 $60,939
13. QUARTERLY FINANCIAL DATA (UNAUDITED):
(Thousands of Dollars) First Second Third Fourth Quarter Quarter Quarter Quarter Annual Total operating revenues $279,241 $244,485 $329,673 $265,034 $1,118,433 Operating income 55,274 38,934 79,363 45,748 219,319 Net Income 36,820 21,327 61,032 26,789 145,968
(Thousands of Dollars) First Second Third Fourth Quarter Quarter Quarter Quarter Annual Total operating revenues $263,576 $222,097 $270,937 $237,771 $994,381 Operating income 49,805 33,452 58,149 40,861 182,267 Net Income 30,055 13,528 36,747 21,833 102,163
DESCRIPTION OF PLANS
Incentive Compensation
To bring total compensation of officers to market levels, the Company has two incentive plans:
Annual Performance Incentive Plan
SCANA has annual Performance Incentive Plans for officers of SCANA and its subsidiaries. The plans promote SCANA's pay-for-performance philosophy, as well as its goal of having a meaningful amount of executive pay "at-risk." Through these plans, financial incentives are provided in the form of annual cash bonuses that are paid only when corporate, business unit and individual goals are achieved.
Short-term incentive awards are targeted below the median of the market. Executives eligible for these plans are assigned threshold, target and maximum bonus levels as a percentage of salary level. Bonuses earned are based on the level of the preestablished goals achieved. Award payouts may increase to a maximum of 1.5 times target, if Company performance exceeds the goals established. Even if this were to occur, payouts would still be below the market median. Award payouts may decrease, generally to a minimum of one-half the target-level awards, if the Company's performance is below targeted goals. Awards earned based on the achievement of preestablished goals may nonetheless be decreased to zero (as was done in 1992), if the Management Development and Corporate Performance Committee (Performance Committee) in its discretion determines that actual results do not warrant the levels of payouts otherwise earned.
The various plans in which officers of SCANA and its subsidiaries participate focus generally on short-term goals affecting profitability, efficiency, quality of service, customer satisfaction and progress toward SCANA's strategic objectives for the Company and its other subsidiaries. New performance categories for officers in the various plans are established annually. Specific performance measures, and their weights, also vary from year to year.
For 1993, the specific measures in each plan, and their weights, for the officers included in the Summary Compensation Table on page 66 are described below. The relationship of performance to payouts for the officers in each plan also is discussed.
For officers of SCANA, 80% of the total award is based on corporate Earnings Per Share ("EPS") goals. The remaining 20% is tied to the achievement of individual performance goals, and is awarded on a discretionary basis.
Specific EPS goals are established that correspond to threshold, target and maximum payouts for the EPS portion of awards. For 1993, SCANA's EPS results were sufficient to result in maximum payouts for that portion of the awards. Individual performance for corporate officers also was determined to be sufficient to result in maximum -level payouts for that portion of the awards. Awards for officers of the Company are based on three performance categories: corporate EPS, numerous corporate and Strategic Business Unit (SBU) financial and productivity goals, and additional SBU strategic initiatives (i.e., activities that focus on improvements in existing operating procedures, quality of service and product, human resources matters, etc.). One-third of the total award is based on results in each performance category. Threshold, target and maximum performance levels are established for each category; payouts will vary based on the actual level of performance achieved.
For 1993, the overall Company performance in all three categories was such that payouts exceeded target-level awards, but were less than the maximum awards possible. Although results for the first two performance categories were above target performance levels, results in the strategic initiative category were below that level.
Long-Term Performance Share Plan
SCANA has a long-term Performance Share Plan for officers of SCANA and its subsidiaries. The long-term Performance Share Plan measures SCANA's Total Shareholder Return ("TSR") relative to a group of peer companies (PSP Peer Group) over a three-year period. The PSP Peer Group includes 97 electric and gas utilities, none of which have annual revenues of less than $100 million.
Total Shareholder Return is stock price increase over the three-year period, plus cash dividends paid during the period, divided by stock price as of the beginning of the period. Comparing SCANA's TSR to a large group of other utilities reflects SCANA's recognition that investors could have invested their funds in other utility companies. Comparing SCANA's TSR against the TSR of the PSP Peer Group measures how well SCANA did when compared to others operating in similar interest, tax, economic and regulatory environments.
Executives eligible to participate in the Performance Share Plan are assigned target award opportunities based primarily on their salary level. In determining award sizes, levels of responsibilities and competitive practices also are considered. Target awards are established at levels slightly below the median of the market and represent a significant portion of executives "at-risk" compensation. But, to provide additional incentive for executives, and to ensure that executives are only rewarded when shareholders gain, actual payouts may exceed the median of the market when performance is outstanding. For lesser performance, awards will be at or below the market median.
Payouts occur when SCANA's TSR is in the top two-thirds of the PSP Peer Group, and vary based on SCANA's ranking against the peer group. Executives earn target payouts at the 50th percentile of three-year performance. Maximum payouts will be made at 1.5 times target when SCANA's TSR is at or above the 75th percentile of the peer group. No payouts will be earned if performance is in the bottom one-third of the peer group. Awards are denominated in shares of SCANA Common Stock and may be paid in either stock or cash or a combination of the two.
For the three-year period from 1991 through 1993, SCANA's TSR was at the 79th percentile of the PSP Peer Group. This resulted in payouts in February 1994 at the maximum level possible.
The combination of the annual Incentive Plan and the Performance Share Plan provides an opportunity to bring a participant's compensation to market levels. The progressive payout formulas in both plans dictate that above-market pay can be earned only for better-than-average corporate financial performance, and that poor performance will result in below- market pay.
The following table shows the target awards made in 1993 for potential payment in 1996 under the long-term Performance Share Plan, and estimated future payouts under that plan at threshold, target and maximum levels.
Defined Contribution Plans
Under the Savings Plan, most of the Company's employees may contribute up to 15% of their eligible earnings. The Company matches each employee's contribution on a dollar-for-dollar basis up to a maximum of 6% of the participant's eligible earnings as limited by the Internal Revenue Code (IRC). Both Company and employee contributions are invested in SCANA's Common Stock.
In addition to the Savings Plan, SCANA has a Supplementary Voluntary Deferral Plan (the "Supplementary Plan") for certain highly compensated employees of the Company and other SCANA subsidiaries. The Supplementary Plan is designed to provide employees whose participation in the Savings Plan is limited by the IRC with the ability to contribute and receive matching contributions in the same percentage as employees generally. However, unlike the Savings Plan where actual shares of SCANA Common Stock are acquired, under the Supplementary Plan the deferred amounts and matches are only accounted for as though shares of common stock had been purchased.
Defined Benefit Plans
In addition to the qualified Retirement Plan for all employees, the Company has Supplemental Executive Retirement Plans ("SERP") for certain eligible employees, including officers. 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 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. 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, 1994 and are not subject to any deduction for Social Security or other offset amounts.
Pension Plan Table
Final Service Years Average Pay 15 20 25 30 35
$125,000 35,130 46,840 58,550 70,260 72,595 150,000 42,630 56,840 71,050 85,260 88,220 175,000 50,130 66,840 83,550 100,260 103,845 200,000 57,630 76,840 96,050 115,260 119,470 225,000 65,130 86,840 108,550 130,260 135,095 250,000 72,630 96,840 121,050 145,260 150,720 300,000 87,630 116,840 146,050 175,260 181,970 350,000 102,630 136,840 171,050 205,260 213,220 400,000 117,630 156,840 196,050 235,260 244,470 450,000 132,630 176,840 221,050 265,260 275,720 500,000 147,630 196,840 246,050 295,260 306,970
The compensation shown in Column (c) of the Summary Compensation Table for the individuals named therein is covered by the Retirement Plan and/or a SERP. Messrs. Gressette, Kenyon, Timmerman, Young and Stedman now have credited service under the Retirement Plan (or its equivalent under the SERP) of 31, 20, 15, 31 and 21 years, respectively.
The Company also has a Key Employee Retention Program (the "Key Employee Retention Program") covering officers and certain other executive employees that provides supplemental retirement and/or death benefits for participants. Under the program the Company will pay to each participant for 180 months, upon retirement at or after age 65, a monthly retirement benefit equal to 25% of the average monthly salary of the participant over his final 36 months of employment prior to age 65, or an optional death benefit payable to a participant's designated beneficiary monthly 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 above are participating in the Key Employee Retention Program. Estimated annual retirement benefits payable at age 65 based on projected eligible compensation (assuming increases of 4% per year) to the five executive officers named in the Summary Compensation Table are as follows: Mr. Gressette - $106,863; Mr. Kenyon - $126,347; Mr. Timmerman - $105,411; Mr. Young - $56,013; and Mr. Stedman - $66,729.
Life Insurance Plans
The Company offers its officers and certain other highly- compensated employees an option to choose whole life insurance (the "Whole Life Option") in lieu of the term life insurance provided employees generally. Under this plan, the employee becomes the owner of a policy with a death benefit of between $200,000 and $550,000 depending upon the salary grade of the employee.
Termination, Severance and Change of Control Arrangements
The Company has a Key Executive Severance Benefit Plan (the "Severance Plan") intended to assure the objective judgment of, and to retain the loyalties of, key executives when the Company is faced with a potential change in control or a change in control by providing a continuation of salary and benefits after a participant's employment is terminated by the Company during a potential change in control, after a change in control without just cause, disability, retirement or death or by the participant for good reason after a change in control. All of the executive officers named in the Summary Compensation Table except Mr. Gressette have been designated as participants in the Severance Plan.
When a potential change in control occurs, a participant is obligated to remain with the Company for six months unless his employment is terminated for disability or normal retirement or until a change in control occurs. Upon a change in control resulting in an officer's termination, the Severance Plan provides for guaranteed severance payments equal to three times the annual compensation of the officer plus payments under certain of the Company's incentive and retirement plans. The officer also would receive an additional amount (a "gross-up" payment) for any IRC Section 4999 excess tax or any such other similar tax applicable to the severance payments. In addition, for 36 months after termination, the officer would receive coverage for medical benefits and life insurance so as to provide the same level of benefits previously enjoyed under group plans or individual policy contracts or otherwise as determined by the Executive Committee of the Board of Directors. Such benefits however would be reduced to the extent that the participant receives similar benefits during the period from another employer.
In addition to the Severance Plan, in the event of a merger, consolidation or acquisition in which SCANA is not the surviving corporation, target awards under the Performance Share Plan will become immediately payable based on SCANA's shareholder return performance as of the end of the most recently completed calendar year for each performance period as to which the grant of target shares has occurred at least six months previously.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
There are no executive officer-director interlocks where an executive officer of the Company serves on the compensation committee of another company that has an executive officer serving on the Company's Board of Directors. Messrs. Hipp, McMaster, Rhodes and Warren are all members of the Long-Term Compensation Committee which administers the Performance Share Plan. Messrs. Hipp and Rhodes also are members of the Performance Committee which generally handles all other executive compensation matters. Mr. Warren was the Chief Executive Officer of the Company from April 23, 1986 until January 31, 1990. Information with respect to transactions with entities with which Messrs. Hipp, McMaster, Rhodes and Warren are connected are described below. Mr. Gressette, Chairman of the Board and Chief Executive Officer of the Company, is an ex-officio (i.e. nonvoting) member of the Performance Committee. The Performance Committee receives his input on compensation matters concerning executive compensation of other officers but the committee deliberates and makes its decisions without his participation.
Mr. Rhodes is the Chairman and Chief Executive Officer of Rhodes Oil Company, Inc. Purchases from Rhodes Oil Company, Inc. totaling $62,500 for fuel oil and gasoline were made during 1993 by the Company. It is anticipated that such purchases will continue in the future.
Mr. McMaster is the President and Manager of Winnsboro Petroleum Company. Purchases from Winnsboro Petroleum Company totaling $77,549 for fuel oil and gasoline were made during 1993 by the Company. It is anticipated that such purchases will continue in the future.
Mr. Hipp, is the President and Chief Executive Officer of The Liberty Corporation. Mr. Hipp and John A. Warren are Directors of The Liberty Corporation. During 1993 certain of the insurance policies purchased by the Company on the lives of employees were written by Liberty Life Insurance Company, a subsidiary of the Liberty Corporation, and it is expected that this relationship will continue in the future. The total amount paid during 1993 by the Company to Liberty Life Insurance Company was $538,905.
COMPENSATION OF DIRECTORS
Fees
All of the Directors of the Company are also Directors of SCANA. During 1993, directors who are not employees of SCANA or its subsidiaries were each paid $14,500 for services rendered, plus $1,500 for each Board meeting attended and $700 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 $150. The fee for attendance at a conference is $500. In addition, Directors are paid, as part of their compensation, travel, lodging and incidental expenses related to attendance at meetings and conferences. Directors who are employees of SCANA or its subsidiaries receive no compensation for serving as directors or attending meetings.
Deferral Plan
The Company has a plan pursuant to which directors may defer all or a portion of their fees for services rendered and meeting attendance. Interest is earned on the deferred amounts at a rate set by the Performance Committee. During 1993 and currently, the rate is set at the announced prime rate of The South Carolina National Bank. During 1993, the only director participating in the plan was Mr. Rhodes. Interest credited to Mr. Rhodes' deferral account during 1993 was $8,526.
Endowment Plan
Each director participates 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 nominated by the 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 of SCANA and 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 SCANA's commitment to quality higher education and is intended to enhance SCANA's ability to attract and retain qualified board members.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
All shares of the Company's Common Stock are held, beneficially and of record, by SCANA Corporation.
The table set forth below indicates as of March 10, 1994, the shares of SCANA's Common Stock beneficially owned by each continuing director and nominee, each of the executive officers named in the Summary Compensation Table on page 66, and the directors and 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 1,243 W. H. Hipp 1,400 W. B. Bookhart, Jr. 6,884 B. D. Kenyon 4,782 W. T. Cassels, Jr. 1,000 F. C. McMaster 10,288 H. M. Chapman 3,127 Henry Ponder 4,806 J. B. Edwards 2,217 J. B. Rhodes 3,434 E. T. Freeman 1,500 W. B. Timmerman 12,889 L. M. Gressette, Jr. 14,649 E. C. Wall, Jr. 7,000 B. A. Hagood 1,140 John A. Warren 50,823 J. H. Young 5,108 R. W. Stedman 6,474
All directors and executive officers as a group (18 persons) TOTAL 138,764 TOTAL PERCENT OF CLASS 0.3%
(1) Includes shares owned by close relatives, the beneficial ownership of which is disclaimed by the director or nominee, as follows: Mr. Amick - 240; Mr. Bookhart - 1,913; Mr. Chapman - 127; Mr. Gressette - 530; Mr. Hagood - 159; Mr. McMaster - 6,365; Mr. Warren - 7,160.
Includes shares purchased through December 31, 1993, but not thereafter, by the Trustee under the Savings Plan.
The information set forth above as to the security ownership 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 28.
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.
Reports on Form 8-K
The Company filed a report on Form 8-K on January 13, 1994 in response to Item 5, "Other Events" regarding the settlement with Westinghouse Electric Corporation of a lawsuit relating to the steam generators provided to the Company's Summer Station.
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/Bruce D. Kenyon (NAME AND TITLE) Bruce D. Kenyon, President and Chief Operating Officer DATE February 15, 1994
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/L. M. Gressette, Jr. (NAME AND TITLE) L. M. Gressette, Jr., Chairman of the Board and Chief Executive Officer and Director DATE February 15, 1994
(ii) Principal financial officer: BY (SIGNATURE) s/W. B. Timmerman (NAME AND TITLE) W. B. Timmerman, Chief Financial Officer DATE February 15, 1994
(iii) Principal accounting officer: BY (SIGNATURE) s/J. E. Addison (NAME AND TITLE) J. E. Addison, Controller DATE February 15, 1994
BY (SIGNATURE) s/B. L. Amick (NAME AND TITLE) B. L. Amick, Director DATE February 15, 1994
BY (SIGNATURE) s/W. B. Bookhart, Jr. (NAME AND TITLE) W. B. Bookhart, Jr., Director DATE February 15, 1994
BY (SIGNATURE) s/W. T. Cassels, Jr. (NAME AND TITLE) W. T. Cassels, Jr., Director DATE February 15, 1994
BY (SIGNATURE) s/H. M. Chapman (NAME AND TITLE) H. M. Chapman, Director DATE February 15, 1994
BY (SIGNATURE) s/J. B. Edwards (NAME AND TITLE) J. B. Edwards, Director DATE February 15, 1994
BY (SIGNATURE) s/E. T. Freeman (NAME AND TITLE) E. T. Freeman, Director DATE February 15, 1994
BY (SIGNATURE) s/B. A. Hagood (NAME AND TITLE) B. A. Hagood, Director DATE February 15, 1994
BY (SIGNATURE) s/W. Hayne Hipp (NAME AND TITLE) W. Hayne Hipp, Director DATE February 15, 1994
BY (SIGNATURE) s/F. C. McMaster (NAME AND TITLE) F. C. McMaster, Director DATE February 15, 1994
BY (SIGNATURE) s/Henry Ponder (NAME AND TITLE) Henry Ponder, Director DATE February 15, 1994
BY (SIGNATURE) s/J. B. Rhodes (NAME AND TITLE) J. B. Rhodes, Director DATE February 15, 1994
BY (SIGNATURE) s/E. C. Wall, Jr. (NAME AND TITLE) E. C. Wall, Jr., Director DATE February 15, 1994
BY (SIGNATURE) s/John A. Warren (NAME AND TITLE) John A. Warren, Director DATE February 15, 1994






ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
All shares of the Company's Common Stock are held, beneficially and of record, by SCANA Corporation.
The table set forth below indicates as of March 10, 1994, the shares of SCANA's Common Stock beneficially owned by each continuing director and nominee, each of the executive officers named in the Summary Compensation Table on page 66, and the directors and 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 1,243 W. H. Hipp 1,400 W. B. Bookhart, Jr. 6,884 B. D. Kenyon 4,782 W. T. Cassels, Jr. 1,000 F. C. McMaster 10,288 H. M. Chapman 3,127 Henry Ponder 4,806 J. B. Edwards 2,217 J. B. Rhodes 3,434 E. T. Freeman 1,500 W. B. Timmerman 12,889 L. M. Gressette, Jr. 14,649 E. C. Wall, Jr. 7,000 B. A. Hagood 1,140 John A. Warren 50,823 J. H. Young 5,108 R. W. Stedman 6,474
All directors and executive officers as a group (18 persons) TOTAL 138,764 TOTAL PERCENT OF CLASS 0.3%
(1) Includes shares owned by close relatives, the beneficial ownership of which is disclaimed by the director or nominee, as follows: Mr. Amick - 240; Mr. Bookhart - 1,913; Mr. Chapman - 127; Mr. Gressette - 530; Mr. Hagood - 159; Mr. McMaster - 6,365; Mr. Warren - 7,160.
Includes shares purchased through December 31, 1993, but not thereafter, by the Trustee under the Savings Plan.
The information set forth above as to the security ownership 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 28.
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.
Reports on Form 8-K
The Company filed a report on Form 8-K on January 13, 1994 in response to Item 5, "Other Events" regarding the settlement with Westinghouse Electric Corporation of a lawsuit relating to the steam generators provided to the Company's Summer Station.
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/Bruce D. Kenyon (NAME AND TITLE) Bruce D. Kenyon, President and Chief Operating Officer DATE February 15, 1994
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/L. M. Gressette, Jr. (NAME AND TITLE) L. M. Gressette, Jr., Chairman of the Board and Chief Executive Officer and Director DATE February 15, 1994
(ii) Principal financial officer: BY (SIGNATURE) s/W. B. Timmerman (NAME AND TITLE) W. B. Timmerman, Chief Financial Officer DATE February 15, 1994
(iii) Principal accounting officer: BY (SIGNATURE) s/J. E. Addison (NAME AND TITLE) J. E. Addison, Controller DATE February 15, 1994
BY (SIGNATURE) s/B. L. Amick (NAME AND TITLE) B. L. Amick, Director DATE February 15, 1994
BY (SIGNATURE) s/W. B. Bookhart, Jr. (NAME AND TITLE) W. B. Bookhart, Jr., Director DATE February 15, 1994
BY (SIGNATURE) s/W. T. Cassels, Jr. (NAME AND TITLE) W. T. Cassels, Jr., Director DATE February 15, 1994
BY (SIGNATURE) s/H. M. Chapman (NAME AND TITLE) H. M. Chapman, Director DATE February 15, 1994
BY (SIGNATURE) s/J. B. Edwards (NAME AND TITLE) J. B. Edwards, Director DATE February 15, 1994
BY (SIGNATURE) s/E. T. Freeman (NAME AND TITLE) E. T. Freeman, Director DATE February 15, 1994
BY (SIGNATURE) s/B. A. Hagood (NAME AND TITLE) B. A. Hagood, Director DATE February 15, 1994
BY (SIGNATURE) s/W. Hayne Hipp (NAME AND TITLE) W. Hayne Hipp, Director DATE February 15, 1994
BY (SIGNATURE) s/F. C. McMaster (NAME AND TITLE) F. C. McMaster, Director DATE February 15, 1994
BY (SIGNATURE) s/Henry Ponder (NAME AND TITLE) Henry Ponder, Director DATE February 15, 1994
BY (SIGNATURE) s/J. B. Rhodes (NAME AND TITLE) J. B. Rhodes, Director DATE February 15, 1994
BY (SIGNATURE) s/E. C. Wall, Jr. (NAME AND TITLE) E. C. Wall, Jr., Director DATE February 15, 1994
BY (SIGNATURE) s/John A. Warren (NAME AND TITLE) John A. Warren, Director DATE February 15, 1994