-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, YXLb5PF558NCrLmbC6/ekPXmp2h4+/06uAnDs5ruMFn1RxLz1Ie5SzEUTNfXy2t8 z+wJovUvCUvS/LIdeyhFow== 0000091882-95-000004.txt : 19950615 0000091882-95-000004.hdr.sgml : 19950615 ACCESSION NUMBER: 0000091882-95-000004 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 9 CONFORMED PERIOD OF REPORT: 19941231 FILED AS OF DATE: 19950316 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTH CAROLINA ELECTRIC & GAS CO CENTRAL INDEX KEY: 0000091882 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 570248695 STATE OF INCORPORATION: SC FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03375 FILM NUMBER: 95521291 BUSINESS ADDRESS: STREET 1: 1426 MAIN ST CITY: COLUMBIA STATE: SC ZIP: 29201 BUSINESS PHONE: 8037483000 MAIL ADDRESS: STREET 1: MAIL CODE 073 CITY: COLUMBIA STATE: SC ZIP: 29218 10-K 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-K (Mark One) x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the fiscal year ended December 31, 1994 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from to Commission File Number 1-3375 SOUTH CAROLINA ELECTRIC & GAS COMPANY (Exact name of registrant as specified in its charter) SOUTH CAROLINA 57-0248695 (State or other jurisdiction of (IRS employer incorporation or organization) identification no.) 1426 MAIN STREET, COLUMBIA, SOUTH CAROLINA 29201 (Address of principal executive offices) (Zip code) Registrant's telephone number, including area code (803) 748-3000 Securities registered pursuant to 12(b) of the Act: Title of each class Name of each exchange on which registered 5% Cumulative Preferred Stock par value $50 per share New York Stock Exchange Securities registered pursuant to 12(g) of the Act: Title of Class The Class is comprised of the following series of Cumulative Preferred Stock, par value $50 per share or $100 per share, having a periodic sinking fund: 9.40% Cumulative Preferred Stock 8.72% Cumulative Preferred Stock par value $50 per share par value $50 per share 8.12% Cumulative Preferred Stock 7.70% Cumulative Preferred Stock par value $100 per share par value $100 per share Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file for the past 90 days. Yes x . No . Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [x] State the aggregate market value of the voting stock held by nonaffiliates of the registrant. The aggregate market value shall be computed by reference to the price at which the stock was sold, or the average bid and asked prices of such stock, as of a specified date within 60 days prior to the date of filing. (See definition of affiliate in Rule 405.) Note. If a determination as to whether a particular person or entity is an affiliate cannot be made without involving unreasonable effort and expense, the aggregate market value of the common stock held by non-affiliates may be calculated on the basis of assumptions reasonable under the circumstances, provided that the assumptions are set forth in this form. The aggregate market value of the voting stock held by nonaffiliates of the registrant as of February 28, 1994 was zero. APPLICABLE ONLY TO REGISTRANTS INVOLVED IN BANKRUPTCY PROCEEDINGS DURING THE PRECEDING FIVE YEARS: Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes No (APPLICABLE ONLY TO CORPORATE REGISTRANTS) Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. As of February 28, 1995 there were issued and outstanding 40,296,147 shares of the registrant's common stock, $4.50 par value, all of which were held, beneficially and of record, by SCANA Corporation. DOCUMENTS INCORPORATED BY REFERENCE. List hereunder the following documents if incorporated by reference and the Part of the Form 10-K (e.g., Part I, Part II, etc.) into which the document is incorporated: (1) any annual report to security-holders; (2) any proxy or information statement; and (3) any prospectus filed pursuant to Rule 424(b) or (c) under the Securities Act of 1933. The listed documents should be clearly described for identification purposes (e.g., annual report to security-holders for fiscal year ended December 24, 1980). NONE 2 TABLE OF CONTENTS Page DEFINITIONS ....................................................... 4 PART I Item 1. Business ............................................ 5 Item 2. Properties .......................................... 17 Item 3. Legal Proceedings ................................... 19 Item 4. Submission of Matters to a Vote of Security Holders ................................... 19 PART II Item 5. Market for Registrant's Common Stock and Related Security Holder Matters ................ 19 Item 6. Selected Financial Data ............................. 20 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ...... 21 Item 8. Financial Statements and Supplementary Data ......... 28 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ................ 54 PART III Item 10. Directors and Executive Officers of the Registrant ......................................... 54 Item 11. Executive Compensation .............................. 59 Item 12. Security Ownership of Certain Beneficial Owners and Management .............................. 63 Item 13. Certain Relationships and Related Transactions ...... 63 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ............................ 63 SIGNATURES ........................................................ 64 3 DEFINITIONS The following abbreviations used in the text have the meaning set forth below unless the context requires otherwise: ABBREVIATION TERM AFC......................... Allowance for Funds Used During Construction BTU......................... British Thermal Unit Circuit Court............... South Carolina Circuit Court Clean Air Act............... Clean Air Act Amendments of 1990 Company..................... South Carolina Electric & Gas Company Consumer Advocate........... Consumer Advocate of South Carolina Dekatherm................... One million BTUs DHEC........................ South Carolina Department of Health and Environmental Control DOE......................... United States Department of Energy EPA......................... United States Environmental Protection Agency FERC........................ United States Federal Energy Regulatory Commission Fuel Company................ South Carolina Fuel Company, Inc., an affiliate GENCO....................... South Carolina Generating Company, Inc., an affiliate KVA......................... Kilovolt-ampere KW.......................... Kilowatt KWH......................... Kilowatt-hour LNG......................... Liquefied Natural Gas MCF......................... Thousand Cubic Feet MW.......................... Megawatt NEPA........................ National Energy Policy Act of 1992 NRC......................... United States Nuclear Regulatory Commission Peoples..................... Peoples Natural Gas Company of South Carolina Pipeline Corporation........ South Carolina Pipeline Corporation, an affiliate PSA......................... The South Carolina Public Service Authority PSC......................... The Public Service Commission of South Carolina PUHCA....................... Public Utility Holding Company Act of 1935 SCANA....................... SCANA Corporation and subsidiaries Southern Natural............ Southern Natural Gas Company Summer Station.............. V. C. Summer Nuclear Station Supreme Court............... South Carolina Supreme Court Transco..................... Transcontinental Gas Pipeline Corporation USEC........................ United States Enrichment Corporation Westinghouse................ Westinghouse Electric Corporation Williams Station............ A. M. Williams coal-fired, electric generating station owned by GENCO 4 PART I 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 4,009 full-time, permanent employees as of December 31, 1994 as compared to 4,166 full-time, permanent employees as of December 31, 1993. 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 20,000 square miles. The total 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, 1994, 1993 and 1992 is contained in Note 11 of Notes to Consolidated Financial Statements and all such information is incorporated herein by reference. Competition The electric utility industry has begun a major transition that could lead to expanded market competition and less regulatory protection. The transition began with the enactment of the Public Utility Regulatory Policies Act of 1978 which facilitated the entry of competitors into the electric generation business. Subsequently, NEPA was enacted in 1992 to promote competition among utility and nonutility generators in the wholesale electric generation market. Recent initiatives in some states to lessen regulation and promote competition, particularly with regard to retail transmission access, also have accelerated the utility industry's transition. Future deregulation of electric wholesale and retail markets will create opportunities to compete for new and existing customers and markets. As a result, profit margins and asset values of some utilities could be adversely affected. The pace of deregulation, the future market price of electricity, and the regulatory actions which may be taken by the PSC in response to the changing environment cannot be predicted. However, the Company is aggressively pursuing actions to position itself strategically for the transformed environment. To enhance its flexibility and responsiveness to change, the Company reorganized its operations around Strategic Business Units. Maintaining a competitive cost structure is of paramount importance in the utility's strategic plan. The Company has undertaken a variety of initiatives, including reductions in operation and maintenance costs and in staffing levels. The Company believes that these actions as well as numerous others that have been and will be taken demonstrate its ability and commitment to succeed in the new operating environment to come. 5 CAPITAL REQUIREMENTS AND FINANCING PROGRAM Capital Requirements The cash requirements of the Company arise primarily from its operational needs and its construction program. During 1995 the Company is expected to meet its capital requirements principally through internally generated funds (approximately 29% 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 customer growth and 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. On June 7, 1993 the PSC issued an order granting the Company a 7.4% annual increase in retail electric rates which was 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 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 1995 and the four-year period 1996-1999 as now scheduled, are as follows: Type of Facilities 1996-1999 1995 (Thousands of Dollars) Electric Plant: Generation. . . . . . . . . . . . . . . . $ 388,193 $129,825 Transmission. . . . . . . . . . . . . . . 92,701 25,928 Distribution. . . . . . . . . . . . . . . 295,571 67,283 Other . . . . . . . . . . . . . . . . . . 69,322 16,874 Nuclear Fuel. . . . . . . . . . . . . . . . 68,171 23,084 Gas . . . . . . . . . . . . . . . . . . . . 60,415 18,895 Transit . . . . . . . . . . . . . . . . . . 1,012 432 Common. . . . . . . . . . . . . . . . . . . 35,090 25,342 Nonutility . . . . . . . . . . . . . . . . 580 175 Total . . . . . . . . . . . . . . $1,011,055 $307,838 The above estimates exclude AFC. Construction The Company's cost estimates for its construction program for the periods 1995 and 1996-1999, 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 and is expected to be complete in late 1995 with commercial operation beginning in early 1996. The estimated cost 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 completion of the new plant, the Company is contracting for additional power as necessary to ensure that the energy demands of its customers can be met. The steam generators at Summer Station were replaced in late 1994 during the regularly scheduled refueling outage. The replacement was completed in 38 days, a new U. S. record and only one day off the world record for a steam generator replacement. The new steam generators are expected to result in shorter, less costly refueling outages, and greater electricity output is expected to result from less required maintenance. During 1994 the Company expended approximately $8.0 million as part of a program to extend the operating lives of certain generating facilities. Additional improvements under the program to be made during 1995 are estimated to cost approximately $9.7 million. 6 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 are at least twice the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 1994 the Bond Ratio was 3.52. 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 $499.8 million at December 31, 1994), Class A Bonds issued on the basis of retirements of Class A Bonds (no retirement credits remained at December 31, 1994), 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 $57 million were available for such purpose as of December 31, 1994), 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, 1994 the New Bond Ratio was 4.85. The following additional financing transactions have occurred since December 31, 1993: On July 21, 1994, the Company issued $100 million of First Mortgage Bonds, 7.70% series due July 15, 2004 to repay short- term borrowings in a like amount. On November 3, 1994 the Company issued $30 million of Pollution Control Facilities Revenue Bonds due November 1, 2024. The proceeds from the sale of the bonds are being used to defray the cost of constructing certain facilities for the disposal of solid waste at the Company's Cope Generating Station under construction in Orangeburg County, South Carolina. 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 debt. 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, 1997. The Company had $265.0 million authorized and unused lines of credit at December 31, 1994. In addition, the Company has a credit agreement for a maximum of $75 million to finance nuclear and fossil fuel inventories with $24.4 million available at December 31, 1994. Fuel Company has issued a promissory note due March 31, 1995 to SCANA for the purchase of $19.4 million of sulfur dioxide emission allowances, including $0.6 million in AFC. 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 are at least one and one-half times the aggregate of all interest charges and preferred stock dividend requirements (Preferred Stock Ratio). For the year ended December 31, 1994 the Preferred Stock Ratio was 2.29. The ratio of earnings to fixed charges (SEC Method) was 3.46, 3.57, 2.73, 3.32 and 3.33 for the years ended December 31, 1994, 1993, 1992, 1991 and 1990, respectively. Additional Capital Requirements In addition to the Company's capital requirements for 1995 described above, approximately $20.7 million will be required for refunding and retiring outstanding securities and obligations. For the years 1996-1999, the Company has an aggregate of $162.9 million of long-term debt maturing (including approximately $59.4 million for sinking fund requirements, of which $59.0 million may be satisfied by deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits) and $9.8 million of purchase or sinking fund requirements for preferred stock. 7 Actual 1995 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. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements. 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, 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. Fuel Company's Commercial Paper and amounts outstanding under the revolving credit agreement, if any, are 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, 1994 Commercial Paper outstanding for nuclear and fossil fuel inventories was approximately $50.6 million at a weighted average interest rate of 6.06%. Such fuel inventories and fuel-related assets and liabilities are included in the Company's financial statements. (See Notes 1M and 4 of Notes to Consolidated Financial Statements.) ELECTRIC OPERATIONS Electric Sales In 1994 residential sales of electricity accounted for 42% of electric sales revenues; commercial sales 30%; industrial sales 21%; sales for resale 4%; and all other 3%. KWH sales by classification for the years ended December 31, 1994 and 1993 are presented below: Sales KWH % Classification 1994 1993 Change (thousands) Residential 5,311,139 5,650,759 (6.01) Commercial 4,848,620 4,844,422 0.09 Industrial 5,161,717 4,887,250 5.62 Sale for resale 1,024,376 1,005,968 1.83 Other 494,030 500,937 (1.38) Total Territorial 16,839,882 16,889,336 (0.29) Interchange 171,046 198,059 (13.64) Total 17,010,928 17,087,395 (0.45) The Company furnishes electricity for resale to three municipalities, three investor-owned utilities, three electric cooperatives and one public power authority. Such sales for resale accounted for 4% of total electric sales revenues in 1994. During 1994 the Company recorded a net increase of 7,538 electric customers, increasing its total customers to 476,438. The electric sales volume decreased for the year ended December 31, 1994 compared to the corresponding period as a result of decreased residential kilowatt-hour sales and interchange power delivered due to unusually mild weather in 1994. The peak demand of 3,444 MW was recorded on January 19, 1994. The all-time record of 3,557 MW was set on July 29, 1993. 8 Electric Interconnections The Company purchases all of the electric generation of Williams Station, owned by GENCO, under a Unit Power Sales Agreement which has been approved by the FERC. Williams Station has a generating capacity of 560 MW. The Company's transmission system is part of the interconnected grid extending over a large part of the southern and eastern 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 1992-1994. 1994 1993 1992 Nuclear: Per million BTU $ .51 $ .47 $ .52 Coal: Company: Per ton $39.92 $39.95 $40.00 Per million BTU 1.57 1.55 1.56 GENCO: Per ton $41.85 $41.64 $41.82 Per million BTU 1.63 1.62 1.63 Weighted Average Cost of All Fuels: Per million BTU $ 1.39 $ 1.33 $ 1.27 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 1992-1994 and the estimates for 1995 and 1996. Percent of Total KWH Generated Actual Estimated 1994 1993 1992 1996 1995 Coal 77% 72% 65% 72% 69% Nuclear 17 22 29 23 26 Hydro 6 5 5 5 5 Natural Gas & Oil - 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, 1994 the Company had approximately a 74-day supply of coal in inventory and GENCO had approximately a 68-day supply. 9 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 1995 (approximately 5.1 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 Initial Final No. of Tons % of 1995 Sulfur Content Expiration Expiration Per Year Requirement per Contract Date (1) Date (1) 482,500 9.5 1.1-1.5 02/28/1996 02/29/2000 359,500 7.0 1.0-1.8 12/31/1996 12/31/2002 562,500 11.0 1.1-2.0 03/31/1997 03/31/2003 144,000 2.8 1.1-1.6 04/30/1995 04/30/1997 981,000 19.2 up to 1.5 12/31/1996 12/31/2002 732,170 14.4 0.75-1.75 04/30/1997 04/30/2003 425,000 8.3 0.8-1.5 06/30/1995 06/30/1999 3,686,670 72.2 (1) Contract extensions beyond the initial expiration date are subject to mutual agreement on price, terms, quantity and quality. All of the above contracts, except the contracts expiring on April 30, 1995 and June 30, 1995 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 1994 had an average sulfur content of 1.26%, 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 at the State level. However, the Company will be required to meet the more stringent Federal emissions standards established by the Clean Air Act (see "Environmental Matters"). The Company currently has adequate supplies of uranium under contract to manufacture nuclear fuel for Summer Station through 1997. The following table summarizes all contract commitments for the stages of nuclear fuel assemblies: Commitment Contractor Regions(1) Term 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 USEC (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. 11 was loaded in 1994 and Region no. 12 will be loaded in 1996. (2) The contract with the USEC is a "requirements" type contract whereby the USEC 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.) 10 GAS OPERATIONS Gas Sales In 1994 residential sales accounted for 49% of gas sales revenues; commercial sales 33%; industrial sales 18%. Dekatherm sales by classification for the years ended December 31, 1994 and 1993 are presented below: Sales Dekatherms % Classification 1994 1993 Change Residential 11,531,558 12,009,444 (4.0) Commercial 9,813,454 8,842,728 11.0 Industrial 10,938,713 5,881,309 86.0 Transportation gas 5,469,728 6,993,817 (21.8) Total 37,753,453 33,727,298 12.0 During 1994 the Company recorded a net increase of 17,155 gas customers including 13,280 customers of Peoples which were combined with the Company in 1994. The total customer count increased to 238,433. The Company purchases all of its natural gas from Pipeline Corporation. The demand for gas is affected by conservation, the weather, the price relationship between gas and alternate fuels and other factors. The deregulation of natural gas prices at the wellhead 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 November 1, 1993 Transco and Southern Natural (Pipeline Corporation's interstate suppliers) began operations under Order No. 636, which deregulated 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. 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 magnitude of this new market. Gas Cost and Supply Pipeline Corporation purchases natural gas under contracts with producers and marketers on a short-term basis at current price indices and on a long-term basis for reliability assurance at index prices plus a gas inventory charge. The gas is brought to South Carolina through transportation agreements with both Southern Natural and Transco. 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 188,000 Transco Firm Transportation 29,300 Total 217,300 11 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 $4.29 in 1994 compared to $3.97 in 1993. To meet the requirements of the Company and its other high priority natural gas customers during periods of maximum demand, Pipeline Corporation supplements its supplies of natural gas from two LNG plants. The LNG plants are capable of storing the lique- fied equivalent of 1,900,000 MCF of natural gas, of which approximately 1,524,833 MCF were in storage at December 31, 1994. On peak days the LNG plants can regasify up to 150,000 MCF per day. Additionally, Pipeline Corporation had contracted for 6,450,727 MCF of natural gas storage space on December 31, 1994, of which 4,550,847 MCF were in storage at such date. 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. 12 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 debt. 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, 1997. The Company holds licenses under the Federal Water Power Act or the Federal Power Act with respect to all its hydroelectric projects. The expiration dates of the licenses covering the projects are as follows: Project Capability (KW) License Expiration Date Neal Shoals 5,000 1993 Stevens Creek 9,000 1993 Columbia 10,000 2000 Saluda 206,000 2007 Parr Shoals 14,000 2020 Fairfield Pumped Storage 512,000 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 with the FERC on December 30, 1991. No competing applications were filed. The Neal Shoals license application was declared to be ready for environmental analysis by FERC Notice dated June 3, 1994, and the Stevens Creek Application was declared to be ready by FERC Notice dated September 6, 1994. 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 is in the process of performing a Multiple-project Environmental Assessment for Neal Shoals and a Single-project Environmental Assessment 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. For the sixth consecutive time, the NRC named Summer Station to its short list of top performing plants. 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. 13 RATE MATTERS The following table presents a summary of significant rate activity for the years 1990-1994 based on test years: REQUESTED GRANTED Date of General Rate Application/ Amount % Increase Date of Amount % of Increase Applications Hearing (Millions) Requested Order (Millions) Granted PSC Electric Retail 12/07/92 $ 72.0* 11.4% 06/07/93 $60.5 84% Retail 01/03/89 $ 27.2 3.7% 07/03/89 $18.2** 67%** Transit Fares 03/12/92 $ 1.7 42.0% 9/14/92 $ 1.0 59%
* As modified to reflect lowering of rate of return the Company was seeking. **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. On October 27, 1994 the PSC issued an order approving the Company's request to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former manufactured gas plants. The billing surcharge, which was effective with the first billing cycle in November 1994 and is subject to annual review, provides for the recovery of approximately $16.2 million representing substantially all site assessment and cleanup costs for the Company's gas operations that had previously been deferred. 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 were 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. 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. Effective with the first billing cycle in December 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 is subject to an annual review by the PSC. The PSC order was based on a return on common equity of 12.25%. On August 26, 1994 the PSC ordered that the WNA be made permanent. 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 nonappealable 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. On April 30, 1994 the PSC issued an order regarding Pipeline Corporation's recovery of take-or-pay cost incurred pursuant to FERC-approved settlements with its upstream interstate pipeline suppliers. This order provided a mechanism for Pipeline Corporation to recover its take-or-pay cost volumetrically over a period of approximately 30 months. The Company receives a credit for payments made prior to the April 30 order which is netted against the current volumetric surcharge. That net cost is recovered by the Company through its purchased gas adjustment clause. 14 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 nonmaterial 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. Fuel Cost Recovery Procedures The PSC has established a fuel cost recovery procedure which determines the fuel component in the Company's retail electric base rates 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 1994 semiannual review of the fuel cost component of electric rates, the PSC voted to increase the rate from 13.0 mills per KWH to 14.16 mills per KWH, a monthly increase of $1.16 for an average customer using 1,000 KWH a month. For the October 1994 review the PSC voted to continue the rate of 14.16 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 1994 review the PSC authorized an increase in the base cost of gas from 47.100 cents per therm to 51.058 cents per therm which resulted in a monthly increase of $3.96 (including applicable taxes) based on an average of 100 therms per month on a residential bill during the heating season. ENVIRONMENTAL MATTERS General Federal and state authorities have imposed environmental control requirements relating primarily to air emissions, wastewater discharges and solid, toxic and hazardous waste management. 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 1992 through 1994, capital expenditures for environmental control amounted to approximately $101.2 million. In addition, approximately $8.8 million, $7.4 million and $5.7 million of environmental control expenditures were made during 1994, 1993 and 1992, 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 $36.2 million for 1995 and $169.3 million for the four- year period 1996 through 1999. These expenditures are included in the Company's construction program. 15 Air Quality Control 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. At December 31, 1994, the Company had purchased $19.4 million in emission allowances and had commitments to purchase $6.8 million of emission allowances in 1995. Low nitrogen oxide burners will be installed to reduce nitrogen oxide emissions. The Company is continuing to refine a 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 $117 million over the 1995-1999 period to retrofit existing facilities and an increased operation and maintenance cost of approximately $1 million per year. To meet compliance requirements through the year 2004, the Company anticipates total capital expenditures of approximately $205 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. Concurrent with renewal of these permits the permitting agency has implemented more rigorous control programs. The Company has 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 differ significantly 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 for electric operations and an eight-year period for gas operations. Such deferred amounts totaled $20.2 million and $19.6 million at December 31, 1994 and 1993, respectively. Estimates to date include, among other things, the costs estimated to be associated with the matters discussed in the following paragraphs. The Company owns five decommissioned manufactured gas plant sites which contain residues of by-product chemicals. The Company has maintained an active review of the sites to monitor the nature and extent of the residual contamination. 16 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 which may have migrated to the City's aquarium site. In 1994 the City of Charleston notified the Company that it considers the Company to be responsible for a $43.5 million increase in costs of the aquarium project attributable to delays resulting from contamination of the Calhoun Park Area Site. The Company believes that it has meritorious defenses against this claim and does not expect its resolution to have a material impact on its financial position or results of operation. 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. The Arkansas Department of Pollution Control and Ecology (ADPCE) has identified the Company as a potentially responsible party for clean- up of PCBs at an abandoned transformer rebuilding plant in Little Rock, Arkansas. No formal notice from ADPCE has been received concerning this issue. The Company does not believe that the resolution of this issue will have a material effect on its results of operations or financial position. 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 requires that the United States government make available by 1998 a permanent repository for high-level radioactive waste and spent nuclear fuel and imposes a fee of 1.0 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 Act also imposes on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. OTHER MATTERS With regard to the Company's insurance coverage for Summer Station, reference is made to Note 10B of Notes to Consolidated Financial Statements, which is incorporated herein by reference. ITEM 2. PROPERTIES The Company's bond indentures, securing the First and Refunding Mortgage Bonds and First Mortgage Bonds issued thereunder, constitute direct mortgage liens on substantially all of its property. 17 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 (2) 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 (3) 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 38,000 Coit Gas/Oil Columbia, SC 1969 30,000 Parr (4) Gas/Oil Parr, SC 1970 60,000 Williams (5) Gas/Oil Goose Creek, SC 1972 49,000 Hagood Gas/Oil Charleston, SC 1991 95,000 Hydro Neal Shoals Carlisle, SC 1905 5,000 Parr Shoals Parr, SC 1914 14,000 Stevens Creek Martinez, GA 1914 9,000 Columbia Columbia, SC 1927 10,000 Saluda Irmo, SC 1930 206,000 Pumped Storage Fairfield Parr, SC 1978 512,000 Total (6) 3,316,000 (1) Summer rating. (2) Excludes Cope Electric Generating Station, a 385,000 KW plant currently under construction and scheduled for commercial operation in early 1996. (3) Represents the Company's two-thirds portion of the Summer Station. (4) 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. (5) The two gas turbines at Williams are leased and have a net capability of 49,000 KW. This lease expires on June 29, 1997. (6) Excludes Williams Station. 18 The Company owns 445 substations having an aggregate transformer capacity of 18,885,437 KVA. The transmission system consists of 3,057 miles of lines and the distribution system consists of 15,421 pole miles of overhead lines and 3,122 trench miles of underground lines. GAS Natural Gas The Company's gas system, including the Peoples system acquired by SCANA and transferred to the Company on January 1, 1994, consists of approximately 6,719 miles of three-inch equivalent distribution pipelines and approximately 11,078 miles of distribution mains and related service facilities. Propane The Company has propane air peak shaving facilities which can supplement the supply of natural gas by gasifying propane to yield the equivalent of 102,000 MCF per day of natural gas. TRANSIT The Company owns 97 motor coaches which operate on a route system of 285 miles. 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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not Applicable PART II 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 1994 and 1993 the Company paid $115.1 million and $108.6 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, 1994 approximately $13.2 million of retained earnings were restricted as to payment of cash dividends on common stock. 19 ITEM 6. SELECTED FINANCIAL DATA For the Years Ended December 31, 1994 1993 1992 1991 1990 STATEMENT OF INCOME DATA (Thousands of Dollars except statistics) Operating Revenues: Electric $ 975,526 $ 940,547 $ 829,938 $ 867,685 $ 851,676 Gas 201,746 174,035 160,820 150,788 147,794 Transit 4,002 3,851 3,623 3,869 4,033 Total Operating Revenues 1,181,274 1,118,433 994,381 1,022,342 1,003,503 Operating Expenses: Fuel used in electric generation and purchased power 289,481 275,298 242,122 262,756 254,489 Gas purchased for resale 127,846 107,722 95,854 93,179 94,358 Other operation and maintenance 272,145 268,233 260,098 248,601 243,735 Depreciation and amortization 106,952 101,220 97,064 91,618 87,021 Taxes 154,432 146,641 116,976 129,482 125,954 Total Operating Expenses 950,856 899,114 812,114 825,636 805,557 Operating Income 230,418 219,319 182,267 196,706 197,946 Other Income: Allowance for equity funds used during construction 7,989 7,496 4,577 2,966 1,308 Other (718) (911) (1,571) 317 (2,267) Total Other Income 7,271 6,585 3,006 3,283 (959) Income Before Interest Charges 237,689 225,904 185,273 199,989 196,987 Interest Charges (Credits): Interest 92,550 85,222 86,994 81,340 79,481 Allowance for borrowed funds used during construction (6,904) (5,286) (3,884) (4,187) (3,333) Total Interest Charges, Net 85,646 79,936 83,110 77,153 76,148 Net Income 152,043 145,968 102,163 122,836 120,839 Dividends on Preferred Stock 5,955 6,217 6,474 6,706 6,911 Earnings Available for Common Stock $ 146,088 $ 139,751 $ 95,689 $ 116,130 $ 113,928 BALANCE SHEET DATA Utility Plant, Net $2,998,132 $2,687,193 $2,503,201 $2,380,761 $2,270,182 Total Assets $3,587,091 $3,189,939 $2,890,953 $2,748,580 $2,625,407 Capitalization: Common equity $1,133,432 $1,051,334 $ 963,741 $ 840,505 $ 821,373 Preferred stock: Not subject to purchase or sinking funds 26,027 26,027 26,027 26,027 26,027 Subject to purchase or sinking funds, Net 49,528 52,840 56,154 59,469 62,704 Long-term debt (excludes current portion) 1,219,991 1,097,043 945,964 993,674 779,524 Total Capitalization $2,428,978 $2,227,244 $1,991,886 $1,919,675 $1,689,628 OTHER STATISTICS Electric: Customers (Year-End) 476,438 468,901 461,928 453,687 446,544 Territorial Sales (Million KWH) 16,840 16,889 15,801 15,702 15,394 Residential: Average annual use per customer (KWH) 13,048 14,077 13,037 13,246 13,330 Average annual rate per KWH $.0743 $.0707 $.0695 $.0700 $.0707 Gas: Customers (Year-End) 238,433 221,278 218,582 214,485 210,326 Sales (Thousand Therms) 322,837 267,335 256,495 247,483 252,373 Residential: Average annual use per customer (therms) 538 606 577 522 497 Average annual rate per therm $.84 $.76 $.74 $.77 $.77 20 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS COMPETITION The electric utility industry has begun a major transition that could lead to expanded market competition and less regulatory protection. The transition began with the enactment of the Public Utility Regulatory Policies Act of 1978 which facilitated the entry of competitors into the electric generation business. Subsequently, NEPA was enacted in 1992 to promote competition among utility and nonutility generators in the wholesale electric generation market. Recent initiatives in some states to lessen regulation and promote competition, particularly with regard to retail transmission access, also have accelerated the utility industry's transition. Future deregulation of electric wholesale and retail markets will create opportunities to compete for new and existing customers and markets. As a result, profit margins and asset values of some utilities could be adversely affected. The pace of deregulation, the future market price of electricity, and the regulatory actions which may be taken by the PSC in response to the changing environment cannot be predicted. However, the Company is aggressively pursuing actions to position itself strategically for the transformed environment. To enhance its flexibility and responsiveness to change, the Company reorganized its operations around Strategic Business Units. Maintaining a competitive cost structure is of paramount importance in the utility's strategic plan. The Company has undertaken a variety of initiatives, including reductions in operation and maintenance costs and in staffing levels. The Company believes that these actions as well as numerous others that have been and will be taken demonstrate its ability and commitment to succeed in the new operating environment to come. 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 generally 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 and is expected to be complete in late 1995 with commercial operation beginning in early 1996. The estimated cost 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 2B 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 which was 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 estimated primary cash requirements for 1995, excluding requirements for fuel liabilities and short-term borrowings (including notes payable to affiliated companies), and the actual primary cash requirements for 1994 are as follows: 1995 1994 (Thousands of Dollars) Property additions and construction expenditures, excluding allowance for funds used during construction (AFC) $284,754 $378,912 Nuclear fuel expenditures 23,084 27,429 Maturing obligations, redemptions and sinking and purchase fund requirements 20,616 5,060 Total $328,454 $411,401 21 Approximately 22% of total cash requirements (excluding dividends) was provided from internal sources in 1994 as compared to 20.0% in 1993. 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 are at least twice the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 1994 the Bond Ratio was 3.52. 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 $499.8 million at December 31, 1994), Class A Bonds issued on the basis of retirements of Class A Bonds (no earned retirement credits remained at December 31, 1994) 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 $57 million were available for such purpose as of December 31, 1994), 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, 1994 the New Bond Ratio was 4.85. The following financing transactions have occurred since December 31, 1993: On July 21, 1994 the Company issued $100 million of First Mortgage Bonds, 7.70% series due July 15, 2004 to repay short- term borrowings in a like amount. On November 3, 1994 the Company issued $30 million of Pollution Control Facilities Revenue Bonds due November 1, 2024. The proceeds from the sale of the bonds are being used to defray the cost of constructing certain facilities for the disposal of solid waste at the Company's Cope Generating Station under construction in Orangeburg County, South Carolina. 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, 1997. The Company had $265.0 million authorized and unused lines of credit at December 31, 1994. In addition, the Company has a credit agreement for a maximum of $75 million to finance nuclear and fossil fuel, with $24.4 million available at December 31, 1994. Fuel Company has issued a promissory note due March 31, 1995 to SCANA for the purchase of $19.4 million of sulfur dioxide emission allowances, including $0.6 million in AFC. 22 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 are at least one and one-half times the aggregate of all interest charges and preferred stock dividend requirements (Preferred Stock Ratio). For the year ended December 31, 1994 the Preferred Stock Ratio was 2.29. The Company anticipates that its 1995 cash requirements of $328.5 million will be met through internally generated funds (approximately 29.4% 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 1995 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. At December 31, 1994, the Company had purchased $19.4 million in emission allowances and had commitments to purchase $6.8 million of emission allowances in 1995. Low nitrogen oxide burners will be installed to reduce nitrogen oxide emissions. The Company is continuing to refine a compliance plan that must be filed with the U.S. Environmental Protection Agency (EPA) by January 1, 1996. The Company currently estimates that, excluding GENCO, air emissions control equipment will require capital expenditures of $117 million over the 1995-1999 period to retrofit existing facilities and an increased operation and maintenance cost of approximately $1 million per year. To meet compliance requirements through the year 2004, the Company anticipates total capital expenditures of approximately $205 million. The Federal Clean Water Act, as amended, provides for the imposition of effluent limitations that require various levels of treatment for each wastewater discharge. Under this Act, compliance with applicable limitations is achieved under a national permit program. Discharge permits have been issued for all and renewed for nearly all of the Company's and GENCO's generating units. Concurrent with renewal of these permits, the permitting agency has implemented more rigorous control programs. The Company has 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. 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 differ significantly 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 for electric operations and an eight-year period for gas operations. Such deferred amounts totaled $20.2 million and $19.6 million at December 31, 1994 and 1993, respectively. Estimates to date include, among other things, the costs associated with the matters discussed in the following paragraphs. 23 The Company owns five decommissioned manufactured gas plant sites which contain residues of by-product chemicals. The Company maintains an active review of the 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 the EPA. The Company is also working with the City of Charleston to investigate potential contamination from the manufactured gas plant which may have migrated to the City's aquarium site. In 1994 the City of Charleston notified the Company that it considers the Company to be responsible for a $43.5 million increase in costs of the aquarium project attributable to delays resulting from contamination of the Calhoun Park Area Site. The Company believes it has meritorious defenses against this claim and does not expect its resolution to have a material impact on its financial position or results of operations. 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. The Arkansas Department of Pollution Control and Ecology (ADPCE) has identified the Company as a PRP for clean-up of PCBs at an abandoned transformer rebuilding plant in Little Rock, Arkansas. No formal notice from ADPCE has been received concerning this issue. The Company does not believe that the resolution of this issue will have a material effect on the Company's results of operations or financial position. 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, based on a test year. These rates were 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 anticipates filing for electric rate relief in 1995. The filing is anticipated to encompass primarily the remaining costs of completing the construction of the Cope Generating Station. The Company's regulated business operations are likely to be impacted by the NEPA and FERC Order No. 636. NEPA is designed to create a more competitive wholesale power supply market by creating "exempt wholesale generators" and by potentially requiring utilities owning transmission facilities to provide transmission access to wholesalers. 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. 24 RESULTS OF OPERATIONS Overview Net income and the percent increase (decrease) from the previous year for the years 1994, 1993 and 1992 were as follows: 1994 1993 1992 Net income $152,043 $145,968 $102,163 Percent increase (decrease) in net income 4.16% 42.9% (16.8%) 1994 Net income increased for 1994 primarily due to an increase in the electric and gas margins which more than offset increases in other operating expenses. 1993 Net income increased for 1993 primarily due to an increase in the electric margin which more than offset increases in other operating expenses. 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. An equity portion of AFC is included in nonoperating income and a debt portion of AFC is included in interest charges (credits) as noncash items, both which have the effect of increasing reported net income. AFC represented approximately 6.3% of income before income taxes in 1994, 5.6% in 1993 and 5.5% in 1992. Electric Operations Electric sales margins for 1994, 1993 and 1992 were as follows: 1994 1993 1992 (Millions of Dollars) Electric revenues $974.3 $940.2 $844.5 (Provision) for rate refunds 1.2 0.3 (14.6) Net Electric operating revenues 975.5 940.5 829.9 Less: Fuel used in electric generation 176.6 164.2 161.7 Purchased power 112.9 111.1 80.4 Margin $686.0 $665.2 $587.8 1994 The 1994 electric sales margin increased from 1993 primarily as a result of an increase in retail electric rates phased in over a two-year period beginning in June 1993 and an increase in industrial sales which more than offset the negative impact of a six percent decrease in residential sales of electricity due to milder weather in 1994. 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 against earnings recorded in 1992 related to the August 31, 1992 retail electric rate ruling from the Supreme Court (see Note 2F of Notes to Consolidated Financial Statements). Increases (decreases) in megawatt hour (MWH) sales volume by classes are presented in the following table: Increase (Decrease) From Prior Year Volume (MWH) Classification 1994 1993 Residential (339,620) 494,874 Commercial 4,198 305,560 Industrial 274,467 203,178 Sale for Resale (excluding interchange) 18,408 59,611 Other (6,907) 24,873 Total territorial (49,454) 1,088,096 Interchange (27,013) 121,013 Total (76,467) 1,209,109 25 The electric sales volume decreased for the year ended December 31, 1994 compared to the corresponding prior period as a result of decreased residential kilowatt hour sales and interchange power delivered due to milder weather in 1994. The peak demand of 3,444 MW was recorded on January 19, 1994. The all-time peak demand record of 3,557 MW was set on July 29, 1993. Gas Operations Gas sales margins for 1994, 1993 and 1992 were as follows: 1994 1993 1992 (Millions of Dollars) Gas revenues $201.7 $174.0 $160.8 Less: Gas purchased for resale 127.8 107.7 95.8 Margin $ 73.9 $ 66.3 $ 65.0 1994 The 1994 gas sales margin increased from 1993 primarily as a result of increases in interruptible gas sales. 1993 The 1993 gas sales margin increased from 1992 primarily as a result of increases in higher margin residential and regular commercial sales. Increases (decreases) in dekatherm (DT) sales volume by classes, including transportation gas, are presented in the following table: Increase (Decrease) From Prior Year Volume (DT) Classification 1994 1993 Residential (477,886) 723,356 Commercial 970,726 (186,529) Industrial 5,057,404 547,193 Transportation Gas (1,524,089) 1,087,120 Total 4,026,155 2,171,140 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 1994 1993 (Millions of Dollars) Other operation and maintenance $ 3.9 $ 8.1 Depreciation and amortization 5.7 4.2 Income taxes 2.8 29.9 Other taxes 5.0 (0.2) Total $17.4 $42.0 1994 Other operation and maintenance expenses increased for 1994 primarily due to an increase in the costs of postretirement benefits other than pensions. These costs are accrued in accordance with Financial Accounting Standards Board Statement No. 106 (See Note 1J of Notes to Consolidated Financial Statements.) The increase in depreciation and amortization expenses is attributable to property additions and to increases in depreciation rates. The increase in other taxes reflects an increase in property taxes of approximately $5 million. 26 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. Interest Expense Increases (decreases) in interest expense are presented in the following table: Increase (Decrease) From Prior Year Classification 1994 1993 (Millions of Dollars) Interest on long-term debt, net $8.0 $ (.8) Other interest expense (.6) (1.0) Total $7.4 $(1.8) 1994 The increase in interest expense, excluding the debt component of AFC, is primarily attributable to the issuance of $100 million of First Mortgage Bonds in July and $30 million of Pollution Control Facilities Revenue Bonds in November, both to finance utility construction, and to the issuance of long-term debt during 1993. 1993 Interest expense, excluding the debt component of AFC, decreased 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. 27 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, 1994 and 1993... 30 Consolidated Statements of Income and Retained Earnings for the years ended December 31, 1994, 1993 and 1992............. 32 Consolidated Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992............................. 33 Consolidated Statements of Capitalization as of December 31, 1994 and 1993................................... 34 Notes to Consolidated Financial Statements..................... 36 Supplemental financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is included in the consolidated financial statements or in the notes thereto. 28 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, 1994 and 1993 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, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1994 and 1993 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. s/Deloitte & Touche LLP DELOITTE & TOUCHE LLP Columbia, South Carolina February 6, 1995 29
SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED BALANCE SHEETS December 31, 1994 1993 (Thousands of Dollars) ASSETS Utility Plant (Notes 1, 3 and 4): Electric $3,165,391 $3,067,881 Gas 307,929 272,506 Transit 3,785 3,769 Common 77,327 72,804 Total 3,554,432 3,416,960 Less accumulated depreciation and amortization 1,171,758 1,097,531 Total 2,382,674 2,319,429 Construction work in progress 571,867 338,677 Nuclear fuel, net of accumulated amortization 43,591 29,087 Utility Plant, Net 2,998,132 2,687,193 Nonutility Property and Investments, net of accumulated depreciation (Note 8) 11,931 12,709 Current Assets: Cash and temporary cash investments (Note 8) 346 193 Receivables - customer and other 127,679 119,296 Receivables - affiliated companies (Note 1) 18,121 244 Inventories (at average cost): Fuel (Notes 1, 3 and 4) 31,310 31,192 Materials and supplies 43,228 43,372 Prepayments 14,389 10,089 Accumulated deferred income taxes 17,931 9,015 Total Current Assets 253,004 213,401 Deferred Debits: Emission allowances 19,409 - Unamortized debt expense 11,690 11,060 Unamortized deferred return on plant investment (Notes 1 and 2) 10,614 14,860 Nuclear plant decommissioning fund (Note 1) 30,383 25,103 Other (Note 1) 251,928 225,613 Total Deferred Debits 324,024 276,636 Total $3,587,091 $3,189,939 See Notes to Consolidated Financial Statements. 30 SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED BALANCE SHEETS December 31, 1994 1993 (Thousands of Dollars) CAPITALIZATION AND LIABILITIES Stockholders' Investment (Note 5): Common equity $1,133,432 $1,051,334 Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027 Total Stockholders' Investment 1,159,459 1,077,361 Preferred Stock, Net (Subject to purchase or sinking funds)(Notes 6 and 8) 49,528 52,840 Long-Term Debt, Net (Notes 3, 4 and 8) 1,219,991 1,097,043 Total Capitalization 2,428,978 2,227,244 Current Liabilities: Short-term borrowings (Notes 8 and 9) 111,200 1,011 Notes payable - affiliated companies 19,409 - Current portion of long-term debt (Note 3) 33,042 13,719 Current portion of preferred stock (Note 6) 2,418 2,504 Accounts payable 61,466 68,182 Accounts payable - affiliated companies (Note 1 and 3) 33,357 28,630 Estimated rate refunds and related interest (Note 2) - 2,509 Customer deposits 12,668 12,207 Taxes accrued 46,646 39,965 Interest accrued 21,534 17,764 Dividends declared 28,489 29,982 Other 15,525 10,042 Total Current Liabilities 385,754 226,515 Deferred Credits: Accumulated deferred income taxes (Notes 1 and 7) 503,723 480,808 Accumulated deferred investment tax credits (Notes 1 and 7) 81,546 84,447 Accumulated reserve for nuclear plant decommissioning (Note 1) 30,383 25,103 Other (Note 1) 156,707 145,822 Total Deferred Credits 772,359 736,180 Total $3,587,091 $3,189,939 See Notes to Consolidated Financial Statements. 31 SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS For the Years Ended December 31, 1994 1993 1992 (Thousands of Dollars) Operating Revenues (Notes 1 and 2): Electric $ 975,526 $ 940,547 $ 829,938 Gas 201,746 174,035 160,820 Transit 4,002 3,851 3,623 Total Operating Revenues 1,181,274 1,118,433 994,381 Operating Expenses: Fuel used in electric generation 176,581 164,187 161,691 Purchased power (including affiliated purchases)(Note 1) 112,900 111,111 80,431 Gas purchased from affiliate for resale (Note 1) 127,846 107,722 95,854 Other operation 214,344 207,126 199,819 Maintenance 57,801 61,107 60,279 Depreciation and amortization (Note 1) 106,952 101,220 97,064 Income taxes (Notes 1 and 7) 84,066 81,280 51,382 Other taxes (Note 12) 70,366 65,361 65,594 Total Operating Expenses 950,856 899,114 812,114 Operating Income 230,418 219,319 182,267 Other Income (Note 1): Allowance for equity funds used during construction 7,989 7,496 4,577 Other income (loss), net of income taxes (718) (911) (1,571) Total Other Income 7,271 6,585 3,006 Income Before Interest Charges 237,689 225,904 185,273 Interest Charges (Credits): Interest on long-term debt, net 87,361 79,410 80,217 Other interest expense (Note 1 and 3) 5,189 5,812 6,777 Allowance for borrowed funds used during construction (Note 1) (6,904) (5,286) (3,884) Total Interest Charges, Net 85,646 79,936 83,110 Net Income 152,043 145,968 102,163 Preferred Stock Cash Dividends (At stated rates) (5,955) (6,217) (6,474) Earnings Available for Common Stock 146,088 139,751 95,689 Retained Earnings at Beginning of Year 291,713 262,262 265,864 Common Stock Cash Dividends Declared (Note 5) (113,700) (110,300) (99,291) Retained Earnings at End of Year $ 324,101 $ 291,713 $ 262,262 See Notes to Consolidated Financial Statements. 32 SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1994 1993 1992 (Thousands of Dollars) Cash Flows From Operating Activities: Net income $152,043 $145,968 $102,163 Adjustments to reconcile net income to net cash provided from operating activities: Depreciation and amortization 107,103 101,370 97,212 Amortization of nuclear fuel 13,487 18,156 23,190 Deferred income taxes, net 13,133 56,982 (15,959) Deferred investment tax credits, net (2,901) (3,245) (3,245) Net regulatory asset arising from adoption of SFAS No. 109 (1,985) (40,398) - Allowance for funds used during construction (14,893) (12,782) (8,461) Unamortized loss on reacquired debt (129) (17,094) (112) Early retirements (7,086) (11,840) - Nuclear refueling accrual (4,881) (6,086) 11,862 Over (under) collections, fuel adjustment clause (17,965) (13,728) 7,901 Emission allowances (19,409) - - Changes in certain current assets and liabilities: (Increase) decrease in receivables (26,260) (27,920) 4,319 (Increase) decrease in inventories 26 1,401 1,069 Increase (decrease) in accounts payable (430) 16,757 2,526 Increase (decrease) in estimated rate refunds and related interest (2,509) (15,302) 17,811 Increase (decrease) in taxes accrued 6,681 (11,162) 36 Increase (decrease) in interest accrued 3,770 (8,669) 83 Other, net 13,313 886 (2,457) Net Cash Provided From Operating Activities 211,108 173,294 237,938 Cash Flows From Investing Activities: Utility property additions and construction expenditures (420,947) (300,620) (243,329) Nonutility property and investments (287) (248) (205) Transfer of assets from SCANA 6,285 - - Principal noncash item: Allowance for funds used during construction 14,893 12,782 8,461 Net Cash Used For Investing Activities (400,056) (288,086) (235,073) Cash Flows From Financing Activities: Proceeds: Issuance of notes payable - affiliated companies 19,409 - - Issuance of mortgage bonds 100,000 600,000 - Issuance of pollution control bonds 30,000 - - Equity contributions from parent 43,426 58,142 126,838 Other Long-term debt - 2,562 - Repayments: Mortgage bonds - (430,000) (35,890) Other Long-term debt (1,662) (405) (120) Preferred stock (3,398) (3,295) (3,199) Dividend Payments: Common stock (115,100) (108,641) (96,550) Preferred stock (6,048) (6,247) (6,558) Short-term borrowings, net 110,189 978 (20) Fuel financings, net 13,844 (18,948) (6,628) Advances - affiliated companies, net (1,559) (3,463) (2,899) Net Cash Provided From (Used For) Financing Activities 189,101 90,683 (25,026) Net Increase (Decrease) in Cash and Temporary Cash Investments 153 (24,109) (22,161) Cash and Temporary Cash Investments, January 1 193 24,302 46,463 Cash and Temporary Cash Investments, December 31 $ 346 $ 193 $ 24,302 Supplemental Cash Flows Information: Cash paid for - Interest (includes capitalized interest of $6,904, $5,286 and $3,884) $ 87,255 $ 92,367 $ 86,093 - Income taxes 77,295 79,612 72,584 Noncash Financing Activities: Department of Energy decontamination and decommissioning fund obligation 4,277 4,965 - See Notes to Consolidated Financial Statements. 33 SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 1994 1993 Common Equity (Note 5): (Thousands of Dollars) Common Stock, $4.50 par value, authorized 50,000,000 shares; issued and outstanding, 40,296,147 shares $181,333 $181,333 Premium on common stock 395,072 395,072 Other paid-in capital 238,369 188,713 Capital stock expense (5,443) (5,497) Retained earnings 324,101 291,713 Total Common Equity 1,133,432 47% 1,051,334 47% Cumulative Preferred Stock (Not subject to purchase or sinking funds)(Note 5): $100 Par Value - Authorized 200,000 shares $50 Par Value - Authorized 125,209 shares Shares Outstanding Redemption Price Eventual Series 1994 1993 Current Through Minimum $100 Par 8.40% 197,668 197,668 102.80 11-30-96 101.00 19,767 19,767 $50 Par 5.00% 125,209 125,209 52.50 - 52.50 6,260 6,260 Total Preferred Stock (Not subject to purchase or sinking funds) 26,027 1% 26,027 1% Cumulative Preferred Stock (Subject to purchase or sinking funds)(Notes 6 and 8): $100 Par Value - Authorized 1,550,000 shares Shares Outstanding Redemption Price Eventual Series 1994 1993 Current Through Minimum 7.70% 89,984 92,992 101.00 - 101.00 8,998 9,299 8.12% 126,835 131,899 102.03 - 102.03 12,684 13,190 Total 216,819 224,891 $50 Par Value - Authorized 1,627,074 shares Shares Outstanding Redemption Price Eventual Series 1994 1993 Current Through Minimum 4.50% 19,088 20,800 51.00 - 51.00 954 1,040 4.60% 2,334 3,834 50.50 - 50.50 117 192 4.60%(A) 28,052 30,052 51.00 - 51.00 1,403 1,503 4.60%(B) 78,200 81,600 50.50 - 50.50 3,910 4,080 5.125% 73,000 74,000 51.00 - 51.00 3,650 3,700 6.00% 86,400 89,600 50.50 - 50.50 4,320 4,480 8.72% 127,956 160,000 51.00 12-31-98 50.00 6,398 8,000 9.40% 190,245 197,191 51.175 - 51.175 9,512 9,860 Total 605,275 657,077 $25 Par Value - Authorized 2,000,000 shares; None outstanding in 1994 and 1993 Total Preferred Stock (Subject to purchase or sinking funds) 51,946 55,344 Less: Current portion, including sinking fund requirements 2,418 2,504 Total Preferred Stock, Net (Subject to purchase or sinking funds) 49,528 2% 52,840 3% See Notes to Consolidated Financial Statements. 34 SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 1994 1993 (Thousands of Dollars) Long-Term Debt (Notes 3, 4 and 8): First Mortgage Bonds: Year of Series Maturity 6% 2000 100,000 100,000 6 1/4% 2003 100,000 100,000 7 1/8% 2013 150,000 150,000 7 1/2% 2023 150,000 150,000 7 5/8% 2023 100,000 100,000 7.70% 2004 100,000 - First and Refunding Mortgage Bonds: Year of Series Maturity 4 7/8% 1995 16,000 16,000 5.45% 1996 15,000 15,000 6% 1997 15,000 15,000 6 1/2% 1998 20,000 20,000 7 1/4% 2002 30,000 30,000 9% 2006 145,000 145,000 8 7/8% 2021 155,000 155,000 Pollution Control Facilities Revenue Bonds: 5.95% Series, due 2003 6,660 6,760 Fairfield County Series 1984, due 2014 (6.50%) 56,820 56,820 Richland County Series 1985, due 2014 (6.50%) 5,210 5,210 Fairfield County Series 1986, due 2014 (6.50%) 1,090 1,090 Colleton and Dorchester Counties Series 1987, due 2014 (6.60%) 4,365 4,365 Orangeburg County Series 1994 due 2024 (daily adjusted rate) 30,000 - Capitalized Lease Obligations, due 1991-1997 (various rates between 5 3/4% and 10%) 1,842 2,897 Installment Note Payable, due 1996 1,452 2,277 Department of Energy Decontamination and Decommissioning Obligation 3,922 4,634 Nuclear and Fossil Fuel Liability 50,594 36,750 Total 1,257,955 1,116,803 Less: Current maturities, including sinking fund requirements 33,042 13,719 Unamortized discount 4,922 6,041 Total Long-Term Debt, Net 1,219,991 50% 1,097,043 49% Advances from Affiliated Companies - 1,559 Less: Current portion of advances - affiliated companies - 1,559 Advances from Affiliated Companies, Net - - - Total Capitalization $2,428,978 100% $2,227,244 100% See Notes to Consolidated Financial Statements. 35 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, 1994 and 1993 the Company had approximately $16.3 million and $15.1 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, 1994 and 1993 the Company had approximately $8.8 million and $7.5 million, respectively, payable to GENCO for unit power purchases. Such unit power purchases, which are included in "Purchased power," amounted to approximately $92.8 million, $98.1 million and $73.1 million in 1994, 1993 and 1992, respectively. Fuel Company has issued a promissory note due March 31, 1995 to SCANA for the purchase of $19.4 million of sulfur dioxide emission allowances, including $0.6 million in AFC. Total interest income (expense), based on market interest rates, associated with the Company's advances to affiliated companies was approximately $(8,000), $129,000 and $231,000 in 1994, 1993 and 1992, respectively. Included in "Other interest expense" for 1994, 1993 and 1992 is approximately $279,000, $29,000 and $16,000, 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. 36 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 $923.1 million and $920.2 million as of December 31, 1994 and 1993, respectively. Accumulated depreciation associated with the Company's share of Summer Station was approximately $297.9 million and $285.3 million as of December 31, 1994 and 1993, 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 8.5%, 9.4% and 9.4% for 1994, 1993 and 1992, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process and sulfur dioxide emission allowances is capitalized at the actual interest amount. 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 1994, 1993 and 1992. F. Revenue Recognition Customers' meters are read and bills are rendered on a monthly cycle basis. Base revenue is recorded during the accounting period in which the meters are read. Fuel costs for electric generation are collected through the fuel cost component in retail electric rates. The fuel cost component contained in electric rates is established by the PSC during semiannual fuel cost hearings. Any difference between actual fuel costs and that contained in the fuel cost component is deferred and included when determining the fuel cost component during the next semiannual fuel cost hearing. The Company had undercollected through the electric fuel cost component approximately $3.5 million at December 31, 1994 and overcollected approximately $9.2 million at December 31, 1993 which are included in "Deferred Debits-Other" and "Deferred Credits-Other", respectively. Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the PSC during annual gas cost recovery hearings. Any difference between actual gas cost and that contained in the rates is deferred and included when establishing gas costs during the next annual gas cost recovery hearing. At December 31, 1994 and 1993 the Company had undercollected through the gas cost recovery procedure approximately $16.3 million and $11.0 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 3.01%, 2.97%, and 3.00% for 1994, 1993 and 1992, 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. 37 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 a 4.5% annual rate of inflation, to be $545.3 million including partial reclamation costs. The Company is providing for its share of estimated decommissioning costs of Summer Station over the life of Summer Station. The Company's method of funding decommissioning cost is referred to as COMReP (Cost of Money Reduction Plan). Under this plan, funds collected through rates ($3.2 million and $2.5 million in 1994 and 1993, respectively) are used to purchase insurance policies on the lives of key Company personnel. Through the purchase of insurance contracts, the Company is able to take advantage of income tax benefits and accrue earnings on the fund on a tax- deferred basis at a rate higher than can be achieved using more traditional funding approaches. Amounts for decommissioning collected through electric rates, insurance proceeds, and interest on proceeds less expenses are transferred by the Company to an external trust fund in compliance with the financial assurance requirements of the Nuclear Regulatory Commission. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis. Thus, the trust's sources of decommissioning funds under the COMReP program include investment components of life insurance policy proceeds, return on investments, and the cash transfers from the Company described above. The Company records its liability for decommissioning costs in deferred credits. The staff of the Securities and Exchange Commission has questioned certain of the current accounting practices of the electric utility industry regarding the recognition, measurement and classification of decommissioning costs for the financial statements of electric utilities with nuclear generating facilities. In response to these questions, the Financial Accounting Standards Board has agreed to review the accounting for removal costs, including decommissioning. If the current electric utility industry accounting practices for such decommissioning are changed: (1) annual provisions for decommissioning could increase, and (2) trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction of decommissioning expense. 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. The Company will recover the costs associated with this liability, totaling $4.3 million at December 31, 1994, 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 expected 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. At December 31, 1993, 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 effects of temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers; otherwise, they are charged or credited to income tax expense. 38 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 for the years ended December 31, 1994, 1993 and 1992 included the following components: 1994 1993 1992 (Thousands of Dollars) Service cost--benefits earned during the period $ 8,684 $ 7,629 $ 7,174 Interest cost on projected benefit obligation 21,711 20,413 19,628 Adjustments: Return on plan assets 2,365 (50,389) (28,607) Net amortization and deferral (29,760) 25,936 8,096 Amounts contributed by the Company's affiliates (130) (175) (154) Net periodic pension cost $ 2,870 $ 3,414 $ 6,137 The determination of net periodic pension cost is based upon the following assumptions: 1994 1993 1992 Annual discount rate 7.25% 8.0% 8.0% Expected long-term rate of return on plan assets 8.0% 8.0% 8.0% Annual rate of salary increases 4.75% 5.5% 5.5% The following table sets forth the funded status of the plan at December 31, 1994 and 1993: 1994 1993 (Thousands of Dollars) Actuarial present value of benefit obligations: Vested benefit obligation $205,364 $204,794 Nonvested benefit obligation 13,966 14,085 Accumulated benefit obligation $219,330 $218,879 Plan assets at fair value (invested primarily in equity and debt securities) $347,702 $351,648 Projected benefit obligation 246,318 295,718 Plan assets greater than projected benefit obligation 101,384 55,930 Unrecognized net transition liability 11,307 10,713 Unrecognized prior service costs 9,374 9,294 Unrecognized net gain (102,284) (64,607) Pension asset recognized in Consolidated Balance Sheets $ 19,781 $ 11,330 The accumulated benefit obligation is based on the plan's benefit formulas without considering expected future salary increases. The following table sets forth the assumptions used in determining the amounts shown above for the years 1994, 1993 and 1992. 1994 1993 1992 Annual discount rate used to determine benefit obligations 8.0% 7.25% 8.0% Assumed annual rate of future salary increases for projected benefit obligation 2.5% 4.75% 5.5% 39 The change in the annual discount rate used to determine benefit obligations from 7.25% to 8.0% and the change in the expected salary increase rate from 4.75% to 2.5% as of December 31, 1994 decreased the projected benefit obligation and increased the unrecognized net gain by approximately $67.7 million. In addition to pension benefits, the Company provides certain health care and life insurance benefits to active and retired employees. The costs of postretirement benefits other than pensions are accrued during the years the employees render the service necessary to be eligible for the applicable benefits. Prior to 1993, the Company expensed these benefits, which are primarily health care, as claims were incurred. In its June 1993 electric rate order the PSC approved the inclusion in rates of the portion of increased expenses related to electric operations. The Company expensed approximately $8.6 million and $4.3 million, net of payments to current retirees, for the years ended December 31, 1994 and 1993, respectively. Net periodic postretirement benefit cost for the years ended December 31, 1994 and 1993, included the following components: 1994 1993 (Thousands of Dollars) Service cost--benefits earned during the period $ 2,417 $ 1,908 Interest cost on accumulated postretirement benefit obligation 6,644 5,502 Adjustments: Return on plan assets - - Amortization of unrecognized transition obligation 3,344 3,344 Other net amortization and deferral 860 - Amounts contributed by the Company's affiliates (575) (525) Net periodic postretirement benefit cost $12,690 $10,229 The determination of net periodic postretirement benefit cost is based upon the following assumptions: 1994 1993 Annual discount rate 7.25% 8.0% Health care cost trend rate 11.25% 13.0% Ultimate health care cost trend rate (to be achieved in 2004) 5.25% 6.0% The following table sets forth the funded status of the plan at December 31, 1994 and 1993: 1994 1993 (Thousands of Dollars) Accumulated postretirement benefit obligations for: Retirees $ 59,174 40,865 Other fully eligible participants 4,995 6,841 Other active participants 24,889 25,767 Accumulated postretirement benefit obligation 89,058 73,473 Plan assets at fair value - - Plan assets less accumulated postretirement benefit obligation (89,058) (73,473) Unrecognized net transition liability 61,581 64,925 Unrecognized prior service costs 3,453 - Unrecognized net loss 11,156 4,284 Postretirement benefit liability recognized in Consolidated Balance Sheets $(12,868) (4,264) 40 The accumulated postretirement benefit obligation is based upon the plan's benefit provisions and the following assumptions: 1994 1993 Assumed health care cost trend rate used to measure expected costs 12.0% 11.25% Ultimate health care cost trend rate (to be achieved in 2004) 6.0% 5.25% Annual discount rate 8.0% 7.25% Annual rate of salary increases 2.5% 4.75% 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, 1994 and the accumulated postretirement benefit obligation as of December 31, 1994 would be to increase such amounts by $210,000 and $3.3 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 differ significantly 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 for electric operations and an eight-year period for gas operations. Such deferred amounts totaled $20.2 million and $19.6 million at December 31, 1994 and 1993, respectively, and are included in "Deferred Debits-Other." M. Fuel Inventories 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. Temporary Cash Investments The Company considers temporary cash investments having original maturities of three months or less to be cash equivalents. Temporary cash investments are generally in the form of commercial paper, certificates of deposit and repurchase agreements. O. Reclassifications Certain amounts from prior periods have been reclassified to conform with the 1994 presentation. 41 2. RATE MATTERS: A. On October 27, 1994 the PSC issued an order approving the Company's request to recover through a billing surcharge to its gas customers the costs of environmental cleanup at the sites of former manufactured gas plants. The billing surcharge, which was effective with the first billing cycle in November 1994 and is subject to annual review, provides for the recovery of approximately $16.2 million representing substantially all site assessment and cleanup costs for the Company's gas operations that had previously been deferred. B. 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 were 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. C. 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. D. Effective with the first billing cycle in December 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 is subject to annual review by the PSC. The PSC order was based on a return on common equity of 12.25%. On August 26, 1994, the PSC ordered that the WNA be made permanent. E. 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. On April 30, 1994 the PSC issued an order involving Pipeline Corporation's recovery of take-or-pay cost incurred pursuant to FERC-approved settlements with its upstream interstate pipeline supplier. This order provided a mechanism for Pipeline Corporation to recover its take-or-pay cost volumetrically over a period of approximately 30 months. The Company receives a credit for payments made prior to the April 30 order which is netted against the current volumetric surcharge. That net cost is recovered by the Company through its purchased gas adjustment clause. F. 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 nonmaterial 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. 42 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 1995 through 1999 are summarized as follows: Year Amount Year Amount (Thousands of Dollars) 1995 $33,042 1998 $35,224 1996 82,229 1999 15,234 1997 30,244 Approximately $14.8 million of the portion of long-term debt payable in 1995 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. Certain outstanding long-term debt of an affiliated company (approximately $35.9 million at both December 31, 1994 and 1993) 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 $50.6 million and $36.8 million at December 31, 1994 and 1993 at weighted average interest rates of 6.06% and 3.47%, respectively. 43 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 1994, 1993 and 1992 are summarized as follows: Common Preferred Thousands Shares Shares of Dollars 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 Changes in Retained Earnings: Net Income 152,043 Cash Dividends Declared: Preferred Stock (at stated rates) (5,955) Common Stock (113,700) Equity Contributions from Parent including transfer of assets 49,710 Balance December 31, 1994 40,296,147 322,877 $1,159,459 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, 1994 approximately $13.2 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. 44 The aggregate annual amounts of purchase fund or sinking fund requirements for preferred stock for the years 1995 through 1999 are summarized as follows: Year Amount Year Amount (Thousands of Dollars) 1995 $2,418 1998 $2,440 1996 2,482 1999 2,440 1997 2,440 The changes in "Total Preferred Stock (Subject to Purchase or Sinking Funds)" during 1994, 1993 and 1992 are summarized as follows: Number Thousands of Shares of Dollars 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 Shares Redeemed: $100 par value (8,072) (807) $50 par value (51,802) (2,591) Balance December 31, 1994 822,094 $ 51,946 7. INCOME TAXES: Total income tax expense for 1994, 1993 and 1992 is as follows: 1994 1993 1992 (Thousands of Dollars) Current taxes: Federal $66,597 $60,577 $62,147 State 9,505 6,822 7,852 Total current taxes 76,102 67,399 69,999 Deferred taxes, net: Federal 7,727 12,197 (16,274) State 2,118 4,387 (322) Total deferred taxes 9,845 16,584 (16,596) Investment tax credits: Amortization of amounts deferred (credit) (3,231) (3,245) (3,245) Total income tax expense $82,716 $80,738 $50,158 45 The difference in actual income taxes and the income taxes calculated from the application of the statutory Federal income tax rate (35% for 1994 and 1993 and 34% for 1992) to pretax income is reconciled as follows:
1994 1993 1992 (Thousands of Dollars) Net income $152,043 $145,968 $102,163 Total income tax expense: Charged to operating expenses 84,066 81,280 51,382 Charged (credited) to other income (1,350) (542) (1,224) Total pretax income $234,759 $226,706 $152,321 Income taxes on above at statutory Federal income tax rate $ 82,166 $ 79,347 $ 51,789 Increases (decreases) attributable to: Allowance for funds used during construction (excluding nuclear fuel) (2,796) (2,624) (1,556) Deferred return on plant investment, net of amortization 1,486 1,486 1,444 Depreciation differences 2,994 2,531 2,356 Amortization of investment tax credits (3,231) (3,245) (3,245) State income taxes (less Federal income tax effect) 7,555 7,286 4,970 Deferred income tax flowback at higher than statutory rates (3,647) (3,641) (4,914) Other differences, net (1,811) (402) (686) Total income tax expense $ 82,716 $ 80,738 $ 50,158
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 operations was not material. The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $485.8 million at December 31, 1994 and $471.8 million at December 31, 1993 determined in accordance with Statement No. 109 (see Note 1I) are as follows: 1994 1993 (Thousands of Dollars) Deferred tax assets: Unamortized investment tax credits $ 50,513 $ 52,310 Cycle billing 17,521 15,084 Nuclear operations expenses 206 4,908 Deferred compensation 5,450 5,265 Other postretirement benefits 3,187 1,631 Other 3,627 4,532 Total deferred tax assets 80,504 83,730 Deferred tax liabilities: Property plant and equipment (including DD&A and basis differences) 533,394 526,540 Pension expense 9,022 6,266 Deferred fuel revenue 7,803 931 Reacquired debt 7,146 7,574 Other 8,931 14,212 Total deferred tax liabilities 566,296 555,523 Net deferred tax liability $485,792 $471,793 46 "Total deferred taxes" charged (credited) to income tax expense result from timing differences in recognition of the following items (thousands of dollars): 1992 Charged (credited) to expense: Property plant and equipment (including DD&A and basis differences) $ (5) Deferred fuel revenue (2,947) Property taxes 493 Cycle billing (1,381) Nuclear refueling accrual (4,430) Electric rate refund (6,571) Injuries and damages (1,377) Other, net (378) Total deferred taxes $(16,596) 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, 1991 and 1992 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, 1994 and 1993 are as follows: 1994 1993 Estimated Estimated Carrying Fair Carrying Fair Amount Value Amount Value (Thousands of Dollars) Cash and temporary cash investments $ 346 $ 346 $ 193 $ 193 Investments 61 61 61 61 Short-term borrowings 111,200 111,200 1,011 1,011 Notes payable - affiliated companies 19,409 19,409 - - Total Long-term debt 1,219,991 1,183,823 1,097,043 1,194,522 Total Preferred stock (subject to purchase or sinking funds) 51,946 49,348 55,344 51,618
The information presented herein is based on pertinent information available to the Company as of December 31, 1994 and 1993. 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, 1994, 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. 47 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, 1994, 1993 and 1992 and for the years then ended are as follows: 1994 1993 1992 (Millions of dollars) Authorized lines of credit at year-end $265.0 $212.0 $189.9 Unused lines of credit at year-end $265.0 $212.0 $189.9 Short-term borrowings outstanding at year-end: Commercial paper $111.2 $ 1.0 $ - Weighted average interest rate 6.04% 3.35% - 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 is expected to be complete in late 1995 with commercial operation beginning in early 1996. The estimated cost 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, 1994 is as follows (thousands of dollars): 1995 $59,766 1996 5,603 Total $65,369 Through December 31, 1994 the Company had paid $310 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 $8.9 billion. Each reactor licensee is currently liable for up to $79.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $10 million of the liability per reactor would be assessed per year. The Company's maximum assessment, based on its two-thirds ownership of Summer Station, would be approximately $52.9 million per incident, but not more than $6.7 million per year. 48 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 $8.2 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. Environmental 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 differ significantly from the original estimates. Amounts estimated and accrued to date for site assessment 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 for electric operations and an eight-year period for gas operations. In September 1992 the Environmental Protection Agency (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 which may have migrated to the city's aquarium site. In 1994 the City of Charleston notified the Company that it considers the Company to be responsible for a $43.5 million increase in costs of the aquarium project attributable to delays resulting from contamination of the Calhoun Park Area Site. The Company believes it has meritorious defenses against this claim and does not expect its resolution to have a material impact on its financial position or results of operations. D. Emission Allowance The Company has entered into an agreement with a broker of sulfur dioxide emission allowances to purchase $6.8 million of allowances at a fixed price during 1995. 49 11. SEGMENT OF BUSINESS INFORMATION: Segment information at December 31, 1994, 1993 and 1992 and for the years then ended is as follows: 1994 Electric Gas Transit Total (Thousands of Dollars) Operating revenues $975,526 $201,746 $ 4,002 $1,181,274 Operating expenses, excluding depreciation and amortization 659,610 173,717 10,577 843,904 Depreciation and amortization 95,666 11,060 226 106,952 Total operating expenses 755,276 184,777 10,803 950,856 Operating income (loss) $ 220,250 $ 16,969 $ (6,801) 230,418 Add - Other income, net 7,271 Less - Interest charges 85,646 Net income $ 152,043 Capital expenditures: Identifiable $ 359,510 $ 40,923 $ 347 $ 400,780 Utilized for overall Company operations 20,167 Total $ 420,947 Identifiable assets at December 31, 1993: Utility plant, net $2,717,147 $201,018 $ 1,791 $2,919,956 Inventories 85,113 2,605 495 88,213 Total $2,802,260 $203,623 $ 2,286 3,008,169 Other assets 578,922 Total assets $3,587,091 50 1993 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 Other assets 495,166 Total assets $3,189,939 51 1992 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 Other assets 368,626 Total assets $2,890,953 52 12. QUARTERLY FINANCIAL DATA (UNAUDITED): 1994 (Thousands of Dollars) First Second Third Fourth Quarter Quarter Quarter Quarter Annual Total operating revenues $313,321 $263,033 $327,066 $277,854 $1,181,274 Operating income 63,520 43,316 79,133 44,449 230,418 Net Income 45,340 24,348 57,619 24,736 152,043 1993 (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 53 ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE NONE PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT DIRECTORS The directors listed below were elected April 29, 1994 to hold office until the next annual meeting of the Company's stockholder on April 28, 1995. Name and Year First Became Director Age Principal Occupation; Directorships Bill L. Amick 51 For more than five years, Chairman of the (1990) Board and Chief Executive Officer of Amick Farms, Inc., Batesburg, SC (vertically integrated broiler operation). For more than five years, Chairman and Chief Executive Officer of Amick Processing, Inc. and Amick Broilers, Inc. Director, SCANA Corporation, Columbia, SC. William B. Bookhart, Jr. 53 For more than five years, a partner in (1979) Bookhart Farms, Elloree, SC (general farming). Director, SCANA Corporation, Columbia, SC. William T. Cassels, Jr. 65 For more than five years, Chairman of the (1990) Board, Southeastern Freight Lines, Inc., Columbia, SC (trucking business). Director, SCANA Corporation, Columbia, SC; South Carolina National Corporation, Columbia, SC; Wachovia Bank of South Carolina, N.A., Columbia, SC. Hugh M. Chapman 62 Since January 1, 1992, Chairman of (1988) NationsBank South, Atlanta, GA (a division of NationsBank Corporation, bank holding company). From September 1, 1990 to December 31, 1991, Vice Chairman and Director, C&S/Sovran Corporation, Atlanta, GA. Prior to September 1, 1990, President and Director, Citizens & Southern Corporation, Atlanta, GA and Chairman of the Board, Citizens & Southern South Carolina Corporation, Columbia, SC. Director, SCANA Corporation, Columbia, SC. 54 Name and Year First Became Director Age Principal Occupation; Directorships James B. Edwards, D.M.D. 67 President and Professor of Maxillofacial (1986) Surgery, Medical University of South Carolina, Charleston, SC. U.S. Secretary of Energy from January 1981 to November 1982. Governor of South Carolina, 1975-1979. Director, Phillips Petroleum Co., Bartlesville, OK; Brendle's, Inc., Elkin, NC; Chemical Waste Management, Inc., Chicago, IL; Imo Industries, Inc., Lawrenceville, NJ; Wachovia Bank of SC, Columbia, SC; National Data Corporation, Atlanta, GA; Encyclopedia Britannica, Chicago, IL; SCANA Corporation, Columbia, SC. Elaine T. Freeman 59 For more than five years, Executive Director (1992) of ETV Endowment of South Carolina, Inc. (non-profit organization), Spartanburg, SC. Director National Bank of South Carolina, Columbia, S.C.; SCANA Corporation, Columbia, SC. Lawrence M. Gressette, Jr. 63 Since February 1, 1990, Chairman of the (1987) Board, Chief Executive Officer and President of SCANA Corporation and Chairman of the Board and Chief Executive Officer of all SCANA subsidiaries, including the Company. Director, Wachovia Corporation, Winston- Salem, NC; The Liberty Corporation, Greenville, SC; SCANA Corporation, Columbia, SC. Benjamin A. Hagood 67 Since January 1, 1993, Chairman of the (1974) Board, William M. Bird and Company, Inc., Charleston, SC (wholesale distributor of floor covering material). For more than three years prior to January 1, 1993, President and Director, William M. Bird and Company, Inc., Charleston, SC. Director, SCANA Corporation, Columbia, SC. 55 Name and Year First Became Director Age Principal Occupation; Directorships W. Hayne Hipp 55 For more than five years, President and (1983) Chief Executive Officer, The Liberty Corporation, Greenville, SC (insurance and broadcasting holding company). Director, The Liberty Corporation, Greenville, SC; Wachovia Corporation, Winston-Salem, NC; SCANA Corporation, Columbia, SC. Bruce D. Kenyon 52 Since November 12, 1990, President and Chief (1991) Operating Officer of the Company. From April 4, 1988 to November 9, 1990, Senior Vice President-Division Operations, Pennsylvania Power and Light Company, Allentown, PA. Director, SCANA Corporation, Columbia, SC. F. Creighton McMaster 65 For more than five years, President and (1974) Manager, Winnsboro Petroleum Company, Winnsboro, SC (wholesale distributor of petroleum products). Director, First Union National Bank of South Carolina, Greenville, SC; SCANA Corporation, Columbia, SC. Henry Ponder, Ph.D. 66 For more than five years, President, Fisk (1983) University, Nashville, TN. Director, Third National Bank, Nashville, TN; SCANA Corporation, Columbia, SC. John B. Rhodes 64 For more than five years, Chairman and (1967) Chief Executive Officer, Rhodes Oil Company, Inc., Walterboro, SC (distributor of petroleum products). Director, SCANA Corporation, Columbia, SC. William B. Timmerman 48 Since May 1, 1994, Executive Vice President (1991) of SCANA Corporation. Since August 25, 1993, Assistant Secretary of SCANA Corporation and all of its subsidiaries including the Company. Since August 28, 1991, Chief Financial Officer of the Company. For more than five years prior to May 1, 1994, Senior Vice President and Controller of SCANA Corporation. Director, SCANA Corporation, Columbia, SC. 56 Name and Year First Became Director Age Principal Occupation; Directorships E. Craig Wall, Jr. 57 For more than five years, President and (1982) Director, Canal Industries, Conway, SC (forest products industry). Director, Sonoco Products Company, Hartsville, SC; Ruddick Corporation, Charlotte, NC; Blue Cross/Blue Shield of South Carolina, Columbia, SC; SCANA Corporation, Columbia, SC. 57 EXECUTIVE OFFICERS OF THE COMPANY The Company's officers are elected at the annual organizational meeting of the Board of Directors and hold office until the next such organizational meeting, unless the Board of Directors shall otherwise determine, or unless a resignation is submitted. Positions Held During Name Age Past Five Years Dates L.M. Gressette, Jr. (1) 63 Chairman of the Board and Chief Executive Officer *-present B.D. Kenyon (1) 52 President and Chief Operating Officer 1990-present Senior Vice President - Division Operations, Pennsylvania Power and Light Company *-1990 W.B. Timmerman (1) 48 Executive Vice President, 1994-present SCANA Assistant Secretary 1993-present Chief Financial Officer 1991-present Senior Vice President, *-1994 SCANA Chief Financial Officer and Controller, SCANA *-present G.J. Bullwinkel, Jr. 46 Senior Vice President- Retail Electric 1995-present Senior Vice President- Fossil & Hydro Production 1993-1994 Senior Vice President- Production 1991-1992 Vice President-Customer Relations, Southern Division *-1991 J. L. Skolds 44 Senior Vice President - Generation 1994-present Vice President - Nuclear Operations 1990-1994 General Manager - Nuclear Plant Operations *-1990 W.A. Darby 49 Senior Vice President and General Manager of ServiceCare, Inc., a sister corporation 1994-present Vice President-Gas Operations *-present *Indicates position held at least since March 1, 1990 (1) Also an executive officer of SCANA COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT Each of the executive officers and directors of the Company, listed on pages 54-58, were delinquent in the filing of a Form 3, as required by Section 16(a) of the Exchange Act, regarding the ownership of the Company's equity securities. All of the Company's common stock is held by its parent, SCANA Corporation, and none of the directors and executive officers of the Company own any of the other classes of equity securities of the Company. The required forms, to be filed shortly, will indicate that no equity securities of the Company are owned by the directors and executive officers. 58 ITEM 11. EXECUTIVE COMPENSATION The following table contains information with respect to compensation paid or accrued by SCANA Corporation and its subsidiaries, including the Company, during the years 1994, 1993 and 1992 to the Chief Executive Officer of the Company and to each of the other four most highly compensated executive officers of the Company during 1994 who were serving as executive officers of the Company at the end of 1994. SUMMARY COMPENSATION TABLE Annual Compensation Long-Term Compensation Name and principal position Year Other annual1 Payouts All other Salary Bonus compensa- LTIP2 compensa- ($) ($) tion ($) tion ($) L. M. Gressette, Jr. 1994 416,6094 0 2,255 173,375 24,996 Chairman of the Board, 1993 383,557 186,615 61,6995 266,007 23,013 President, Chief Executive 1992 368,426 0 60,448 82,151 22,104 Officer and Director - SCANA Corporation and the Company and Chairman of the Board and Chief Executive Officer - all SCANA subsidiaries B. D. Kenyon 1994 313,581 96,768 2,649 81,619 18,815 President and Chief Operating 1993 297,760 99,090 4,201 125,792 17,866 Officer 1992 291,355 0 3,265 46,250 17,481 Director - SCANA Corporation and the Company W. B. Timmerman 1994 235,099 19,725 1,323 70,751 14,106 Executive Vice President 1993 220,752 95,738 2,828 109,768 13,245 Chief Financial Officer and 1992 215,817 0 2,303 33,906 12,949 Director - SCANA Corporation Chief Financial Officer and Director - SCANA Corporation and the Company J. H. Young 1994 174,771 50,765 318 45,251 10,486 Senior Vice President 1993 167,566 51,975 1,542 70,508 10,054 Customer Relations 1992 165,102 0 1,084 23,556 9,906 R. W. Stedman 1994 179,020 50,765 21 45,251 10,741 Senior Vice President - 1993 170,361 51,975 1,107 70,508 10,222 Administrative Support Group 1992 167,259 0 985 23,556 10,036
1 Other annual compensation consists of (i) perquisites for those named individuals whose perquisites exceeded the lesser of 10% of their salary and bonus or $50,000 and (ii) payments to cover taxes on benefits. In 1992 and 1993 the perquisites for Mr. Gressette included premiums on a whole life insurance policy in the amount of $50,018. 2 Payments under the long-term Performance Share Plan described hereafter. 3 All other compensation consists solely of Company contributions to defined contribution plans on behalf of the named individual. 4 Reflects actual salary paid in 1994. Base salary of $427,100 became effective in May of 1994. 5 Adjusted from 1993 10-K to include perquisites amounting to $4,324 not previously reflected. 59 Long-Term Performance Share Plan SCANA's Performance Share Plan for officers of SCANA and its subsidiaries measures SCANA's Total Shareholder Return ("TSR") relative to a group of peer companies over a three-year period. The "PSP Peer Group" includes 95 electric and gas utilities, none of which have annual revenues of less than $100 million. TSR 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 the TSR of a large group of other utilities reflects SCANA's recognition that investors could have invested their funds in other utility companies and 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. 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 a combination of stock and cash. For the three-year period from 1992 through 1994, SCANA's TSR was at the 61st percentile of the PSP Peer Group. This resulted in payouts in February 1995 at 122% of target shares awarded paid in a combination of stock and cash. The following table shows the target awards made in 1994 for potential payment in 1997 under the long-term Performance Share Plan, and estimated future payouts under that plan at threshold, target and maximum levels. LONG-TERM INCENTIVE PLAN - AWARDS IN LAST FISCAL YEAR TARGET AWARDS FOR 1994 TO BE PAID IN 1997 Estimated Future Payouts Under Non-Stock Price- Based Plans Number of Performance or Shares, Units Other Period Name or Other Rights Until Maturation Threshold Target Maximum (#) or Payout ($ or #) ($ or #) ($ or #) L. M. Gressette, Jr. 3,430 1994 - 1996 1,372 3,430 5,145 B. D. Kenyon 1,520 1994 - 1996 608 1,520 2,280 W. B. Timmerman 1,320 1994 - 1996 528 1,320 1,980 J. H. Young 800 1994 - 1996 320 800 1,200 R. W. Stedman 800 1994 - 1996 320 800 1,200 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. 60 The following table illustrates the estimated maximum annual benefits payable upon retirement at normal retirement date under the Retirement Plan and the SERPs. Pension Plan Table Final Service Years Average Pay 15 20 25 30 35 $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 87,630 116,840 146,050 175,260 181,970 350,000 102,630 136,840 171,050 205,260 213,220 400,000 117,630 156,840 196,050 235,260 244,470 450,000 132,630 176,840 221,050 265,260 275,720 500,000 147,630 196,840 246,050 295,260 306,970 550,000 162,473 216,631 270,788 324,946 337,854 The compensation shown in the column labeled "Salary" 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 32, 21, 16, 32 and 23 years, respectively. 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, 1995 and are not subject to any deduction for Social Security or other offset amounts. 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, each participant may elect to receive either a monthly retirement benefit for 180 months upon retirement at or after age 65 equal to 25% of the average monthly salary of the participant over his final 36 months of employment prior to age 65, or 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 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 - $111,102; Mr. Kenyon - $127,564; Mr. Timmerman - $108,112; and Young - $56,018. Mr. Stedman retired from the Company effective February 1, 1995 and is receiving an annual benefit of $44,497. 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. 61 COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION There currently exists one executive officer-director interlock where an executive officer of SCANA Corporation serves as a director of another company that has an executive officer serving on the SCANA Board of Directors' committees which deal with compensation matters. Mr. Gressette, Chairman of the Board, Chief Executive Officer and President of the Company began serving as a director of The Liberty Corporation in May 1994. Mr. Hipp is President and Chief Executive Officer of The Liberty Corporation and currently serves as a member of the Management Development and Corporate Performance Committee and the Long-Term Compensation Committee of the Board of Directors which generally handle executive compensation matters. Mr. Gressette is an ex- officio, 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. Since January 1, 1994, the Company has engaged in business transactions with entities with which Messrs. Hipp, Chapman (who is Chairman of the Performance Committee and a member of the Long-Term Compensation Committee), and McMaster (who is a member of the Long-Term Compensation Committee) are related. Information with respect to such transactions can be found in the paragraphs below. Mr. Hipp is the President, Chief Executive Officer and a director of The Liberty Corporation. In January 1994, SCANA and its wholly owned subsidiary SCANA Development Corporation ("SDC") entered into an agreement, amended in March 1994, to sell certain of the assets of SDC to Liberty Properties Group, Inc., a subsidiary of The Liberty Corporation, for approximately $49 million. Closing of the transaction was completed in May 1994. The sale price by SCANA was determined by reference to prices of comparable properties in the same market areas, as negotiated by senior executives of the parties at arms length. An independent certified public accounting firm was retained to review the valuation methodology. In addition, during 1994 certain of the insurance policies purchased by SCANA and its subsidiaries on the lives of employees, officers and directors of the Company 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 1994 by SCANA and its subsidiaries to Liberty Life Insurance Company was $360,785.42. Mr. Chapman is Chairman of NationsBank South, a division of NationsBank Corporation. Since January 1, 1994, SCANA and its subsidiaries, including the Company have engaged in various transactions in which affiliates of NationsBank Corporation acted as lender or provider of lines of credit or credit support to the Company and its subsidiaries. It is anticipated that such transactions will continue in the future. The total amount paid during 1994 by the Company and its subsidiaries to NationsBank Corporation affiliates on account of such transactions was $1,633,503.45. In addition, in January 1995, a NationsBank Corporation affiliate and SCANA entered into a series of forward contracts relating to approximately sixty percent of SCANA's subsidiary's forecasted natural gas production for the years 1995 - 2001, at an average price of $1.88 per dekatherm. Mr. McMaster is the President and Manager of Winnsboro Petroleum Company. Purchases from Winnsboro Petroleum Company totaling $98,464.06 for fuel oil and gasoline were made during 1994 by the Company and its subsidiaries. It is anticipated that such purchases will continue in the future. COMPENSATION OF DIRECTORS Fees During 1994, directors who were not employees of the Company were paid $16,000 annually for services rendered, plus $1,800 for each Board meeting attended and $850 for attendance at a committee meeting which is not held on the same day as a regular meeting of the Board. The fee for attendance at a telephone conference meeting is $200. The fee for attendance at a conference is $850. In addition, directors are paid, as part of their compensation, travel, lodging and incidental expenses related to attendance at meetings and conferences. Directors who are employees of SCANA or its subsidiaries receive no compensation for serving as directors or attending meetings. Deferral Plan SCANA 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 1994 and currently, the rate is set at the announced prime rate of Wachovia Bank of South Carolina. Mr. Cassels and Mr. Rhodes were the only directors participating in the plan during 1994. Mr. Cassels became a participant in January 1994 and Mr. Rhodes in July 1987, and interest credited to their deferral accounts during 1994 was $1,009.92 and $12,741.17, respectively. Endowment Plan Each director participates in the Directors' Endowment Plan, which provides for SCANA 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. 62 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 the shares of SCANA's Common Stock beneficially owned as of March 10, 1995 by each director and nominee, each of the executive officers named in the Summary Compensation Table on page 10, 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. Hayne Hipp 1,400 W. B. Bookhart, Jr. 7,362 B. D. Kenyon 6,629 W. T. Cassels, Jr. 1,000 F. C. McMaster 10,288 H. M. Chapman 3,000 Henry Ponder 5,498 J. B. Edwards 2,274 J. B. Rhodes 3,661 E. T. Freeman 2,090 R. W. Stedman 8,129 L. M. Gressette, Jr. 18,168 W. B. Timmerman 15,131 B. A. Hagood 1,162 E. C. Wall, Jr. 7,000 J. H. Young 5,395 All directors and executive officers as a group (19 persons) TOTAL 118,076 TOTAL PERCENT OF CLASS 0.2% The information set forth above as to the security ownership has been furnished to the Company by such persons. ______________ 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 - 2,062; Mr. Gressette - 530; Mr. Hagood - 163; and Mr. McMaster - 6,365. Includes shares purchased through December 31, 1994, but not thereafter, by the Trustee under the Stock Purchase-Savings Plan. 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. As permitted under Item 601(b)(4)(iii), instruments defining the rights of holders of long-term debt of less than 10 percent of the total consolidated assets of the Company and its subsidiaries, have been omitted and the Company agrees to furnish a copy of such instruments to the Commission upon request. Reports on Form 8-K None 63 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 14, 1995 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, Chief Executive Officer and Director DATE February 14, 1995 (ii) Principal financial officer: BY (SIGNATURE) s/W. B. Timmerman (NAME AND TITLE) W. B. Timmerman, Chief Financial Officer DATE February 14, 1995 (iii) Principal accounting officer: BY (SIGNATURE) s/J. E. Addison (NAME AND TITLE) J. E. Addison, Vice President and Controller DATE February 14, 1995 BY (SIGNATURE) s/B. L. Amick (NAME AND TITLE) B. L. Amick, Director DATE February 14, 1995 BY (SIGNATURE) s/W. B. Bookhart, Jr. (NAME AND TITLE) W. B. Bookhart, Jr., Director DATE February 14, 1995 BY (SIGNATURE) s/W. T. Cassels, Jr. (NAME AND TITLE) W. T. Cassels, Jr., Director DATE February 14, 1995 BY (SIGNATURE) s/H. M. Chapman (NAME AND TITLE) H. M. Chapman, Director DATE February 14, 1995 BY (SIGNATURE) s/J. B. Edwards (NAME AND TITLE) J. B. Edwards, Director DATE February 14, 1995 64 BY (SIGNATURE) s/E. T. Freeman (NAME AND TITLE) E. T. Freeman, Director DATE February 14, 1995 BY (SIGNATURE) s/B. A. Hagood (NAME AND TITLE) B. A. Hagood, Director DATE February 14, 1995 BY (SIGNATURE) s/W. Hayne Hipp (NAME AND TITLE) W. Hayne Hipp, Director DATE February 14, 1995 BY (SIGNATURE) s/F. C. McMaster (NAME AND TITLE) F. C. McMaster, Director DATE February 14, 1995 BY (SIGNATURE) s/Henry Ponder (NAME AND TITLE) Henry Ponder, Director DATE February 14, 1995 BY (SIGNATURE) s/J. B. Rhodes (NAME AND TITLE) J. B. Rhodes, Director DATE February 14, 1995 BY (SIGNATURE) s/E. C. Wall, Jr. (NAME AND TITLE) E. C. Wall, Jr., Director DATE February 14, 1995 65 EX-1 2 SOUTH CAROLINA ELECTRIC & GAS COMPANY Sequentially EXHIBIT INDEX Numbered Number Pages 2. Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession Not Applicable 3. Articles of Incorporation and By-Laws A. Restated Articles of Incorporation of the Company as adopted on June 9, 1994 (Exhibit 3-A to Form 10-Q for the quarter ended June 30, 1994, File No. 1-3375)......................................... # B. Articles of Amendment, dated June 7, 1994, filed June 9, 1994 (Exhibit 3-B to Form 10-Q for the quarter ended June 30, 1994, File No. 1-3375).... # C. Articles of Amendment, dated November 9, 1994 (Filed herewith)......................................... 69 D. Articles of Amendment, dated December 9, 1994 (Filed herewith)......................................... 71 E. Articles of Correction, dated January 17, 1995 (Filed herewith)......................................... 73 F. Articles of Amendment, dated January 13, 1995 and filed January 17, 1995 (Filed herewith)............... 74 G. Copy of By-Laws of the Company as revised and amended thru December 15, 1993 (Exhibit 3-AZ to Form 10-K for the year ended December 31, 1993, File No. 1-3375)......................................... # 4. Instruments Defining the Rights of Security Holders, Including Indentures A. Indenture dated as of January 1, 1945, from the South Carolina Power Company (the "Power Company") to Central Hanover Bank and Trust Company, as Trustee, as supplemented by three Supplemental Indentures dated respectively as of May 1, 1946, May 1, 1947 and July 1, 1949 (Exhibit 2-B to Registration No. 2-26459)................................ # B. Fourth Supplemental Indenture dated as of April 1, 1950, to Indenture referred to in Exhibit 4A, pursuant to which the Company assumed said Indenture (Exhibit 2-C to Registration No. 2-26459)...... # C. Fifth through Fifty-second Supplemental Indentures to Indenture referred to in Exhibit 4A dated as of the dates indicated below and filed as exhibits to the Registration Statements and 1934 Act reports whose file numbers are set forth below.............................................. # December 1, 1950 Exhibit 2-D to Registration No. 2-26459 July 1, 1951 Exhibit 2-E to Registration No. 2-26459 June 1, 1953 Exhibit 2-F to Registration No. 2-26459 June 1, 1955 Exhibit 2-G to Registration No. 2-26459 November 1, 1957 Exhibit 2-H to Registration No. 2-26459 September 1, 1958 Exhibit 2-I to Registration No. 2-26459 September 1, 1960 Exhibit 2-J to Registration No. 2-26459 June 1, 1961 Exhibit 2-K to Registration No. 2-26459 December 1, 1965 Exhibit 2-L to Registration No. 2-26459 June 1, 1966 Exhibit 2-M to Registration No. 2-26459 June 1, 1967 Exhibit 2-N to Registration No. 2-29693 September 1, 1968 Exhibit 4-O to Registration No. 2-31569 June 1, 1969 Exhibit 4-C to Registration No. 33-38580 December 1, 1969 Exhibit 4-Q to Registration No. 2-35388 June 1, 1970 Exhibit 4-R to Registration No. 2-37363 March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324 January 1, 1972 Exhibit 4-C to Registration No. 33-38580 July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291 May 1, 1975 Exhibit 4-C to Registration No. 33-38580 # Incorporated herein by reference as indicated. 66 SOUTH CAROLINA ELECTRIC & GAS COMPANY Exhibit Index (Continued) Sequentially Numbered r Pages 4. (continued) July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908 February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304 December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936 March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662 May 1, 1977 Exhibit 4-C to Registration No. 33-38580 February 1, 1978 Exhibit 4-C to Registration No. 33-38580 June 1, 1978 Exhibit 2-A-3 to Registration No. 2-61653 April 1, 1979 Exhibit 4-C to Registration No. 33-38580 June 1, 1979 Exhibit 4-C to Registration No. 33-38580 April 1, 1980 Exhibit 4-C to Registration No. 33-38580 June 1, 1980 Exhibit 4-C to Registration No. 33-38580 December 1, 1980 Exhibit 4-C to Registration No. 33-38580 April 1, 1981 Exhibit 4-D to Registration No. 33-49421 June 1, 1981 Exhibit 4-D to Registration No. 2-73321 March 1, 1982 Exhibit 4-D to Registration No. 33-49421 April 15, 1982 Exhibit 4-D to Registration No. 33-49421 May 1, 1982 Exhibit 4-D to Registration No. 33-49421 December 1, 1984 Exhibit 4-D to Registration No. 33-49421 December 1, 1985 Exhibit 4-D to Registration No. 33-49421 June 1, 1986 Exhibit 4-D to Registration No. 33-49421 February 1, 1987 Exhibit 4-D to Registration No. 33-49421 September 1, 1987 Exhibit 4-D to Registration No. 33-49421 January 1, 1989 Exhibit 4-D to Registration No. 33-49421 January 1, 1991 Exhibit 4-D to Registration No. 33-49421 February 1, 1991 Exhibit 4-D to Registration No. 33-49421 July 15, 1991 Exhibit 4-D to Registration No. 33-49421 August 15, 1991 Exhibit 4-D to Registration No. 33-49421 April 1, 1993 Exhibit 4-E to Registration No. 33-49421 July 1, 1993 Exhibit 4-D to Registration No. 33-57955 D. Indenture dated as of April 1, 1993 from South Carolina Electric & Gas Company to NationsBank of Georgia, National Association (Filed as Exhibit 4-F to Registration Statement No. 33-49421)......................................... # E. First Supplemental Indenture to Indenture referred to in 4-D dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421)......................... # F. Second Supplemental Indenture to Indenture referred to in 4-D dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955)......................... # 9. Voting Trust Agreement Not Applicable 10. Material Contracts A. Copy of Supplemental Executive Retirement Plan (Exhibit 10-A to Form 10-K for the year ended December 31, 1980)............................................ # 11. Statement Re Computation of Per Share Earnings Not Applicable 12. Statement re Computation of Ratios (Filed herewith)............... 76 13. Annual Report to Security Holders, Form 10-Q or Quarterly Report to Security Holders Not Applicable 16. Letter Re Change in Certifying Accountant Not Applicable # Incorporated herein by reference as indicated. 67 SOUTH CAROLINA ELECTRIC & GAS COMPANY Exhibit Index (Continued) Sequentially Numbered Number Pages 18. Letter Re Change in Accounting Principles Not Applicable 21. Subsidiaries of the Registrant Not Applicable 22. Published Report Regarding Matters Submitted to Vote of Security Holders Not Applicable 23. Consents of Experts and Counsel Consent of Deloitte & Touche LLP........................... 80 24. Power of Attorney Not Applicable 27. Financial Data Schedule Filed herewith 28. Information from Reports furnished to State Insurance Regulatory Authorities Not Applicable 99. Additional Exhibits Not Applicable # Incorporated herein by reference as indicated. 68 EX-2 3 Exhibit 3-C STATE OF SOUTH CAROLINA SECRETARY OF STATE ARTICLES OF AMENDMENT Pursuant to Section 33-10-196 of the 1976 South Carolina Code, as amended, the undersigned corporation adopts the following Articles of Amendment to its Articles of Incorporation: 1. The name of the Corporation is SOUTH CAROLINA ELECTRIC & GAS COMPANY. 2. On , the corporation adopted the following Amendment(s) of its Articles of Incorporation: NOT APPLICABLE 3. The manner, if not set forth in the amendment, in which any exchange, reclassification, or cancellation of issued shares provided for in the Amendment shall be effected, is as follows: (a) The number of redeemable shares of the Corporation reacquired by redemption or purchase is 18,538 itemized as follows: Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 4.50% 1,712 Cumulative Preferred Stock ($50 par value) 4.60% 2,000 Cumulative Preferred Stock ($100 par value) 7.70% 3,000 Cumulative Preferred Stock ($100 par value) 8.12% 4,925 Cumulative Preferred Stock ($50 par value) 9.40% 6,901 (b) The aggregate number of issued shares of the Corporation after giving effect to such cancellation is 41,442,626, itemized as follows: Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 5% 125,209 Cumulative Preferred Stock ($50 par value) 4.60% 3,834 Cumulative Preferred Stock ($50 par value) 4.50% 19,088 Cumulative Preferred Stock ($50 par value) 4.60% (Series A) 28,052 Cumulative Preferred Stock ($50 par value) 5.125% 73,000 Cumulative Preferred Stock ($50 par value) 4.60% (Series B) 78,200 Cumulative Preferred Stock ($50 par value) 6% 86,400 Cumulative Preferred Stock ($50 par value) 9.40% 190,245 Cumulative Preferred Stock ($100 par value) 8.12% 126,835 Cumulative Preferred Stock ($100 par value) 7.70% 89,992 Cumulative Preferred Stock ($100 par value) 8.40% 197,668 Cumulative Preferred Stock ($50 par value) 8.72% 127,956 Common Stock ($4.50 par value) 40,296,147 41,442,626 (c) The amount of the stated capital of the Corporation after giving effect to such cancellation is $259,381,361.50. (d) The number of shares which the Corporation has authority to issue after giving effect to such cancellation is 55,503,783, itemized as follows: 69 Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 5% 125,209 Cumulative Preferred Stock ($50 par value) 4.60% 3,834 Cumulative Preferred Stock ($50 par value) 4.50% 19,088 Cumulative Preferred Stock ($50 par value) 4.60% (Series A) 28,052 Cumulative Preferred Stock ($50 par value) 5.125% 73,000 Cumulative Preferred Stock ($50 par value) 4.60% (Series B) 78,200 Cumulative Preferred Stock ($50 par value) 6% 86,400 Cumulative Preferred Stock ($50 par value) 9.40% 190,245 Cumulative Preferred Stock ($100 par value) 8.12% 126,835 Cumulative Preferred Stock ($100 par value) 7.70% 89,992 Cumulative Preferred Stock ($100 par value) 8.40% 197,668 Cumulative Preferred Stock ($50 par value) 8.72% 127,956 Serial Preferred Stock ($50 par value) (1 vote) 449,755 Serial Preferred Stock ($100 par value) (1 vote) 1,335,505 Serial Preferred Stock ($25 par value) (1/4 vote) 2,000,000 Serial Preferred Stock ($50 par value) (1/2 vote) 572,044 Common Stock ($4.50 par value) 50,000,000 55,503,783 4. (a) / / Amendment(s) adopted by shareholder action. At the date of adoption of the amendment, the number of outstanding shares of each voting group entitled to vote separately on the Amendment, and the vote of such shares was: Number of Number of Number of Votes Number of Undisputed Voting Outstanding Votes Entitled Represented at Shares Voted Group Shares to be Cast the meeting For Against (b) / X / The Amendment(s) was duly adopted by the incorporators or board of directors without shareholder approval pursuant to Section 33-6-102(d), 33-10-102 and 33-10-105 of the 1976 South Carolina Code, as amended, and shareholder action was not required. 5. Unless a delayed date is specified, the effective date of these Articles of Amendment shall be the date of acceptance for filing by the Secretary of State (See Section 33-1-230(b)). Date November 9, 1994 SOUTH CAROLINA ELECTRIC & GAS COMPANY By: K. B. Marsh Secretary 70 EX-3 4 Exhibit 3-D STATE OF SOUTH CAROLINA SECRETARY OF STATE ARTICLES OF AMENDMENT Pursuant to Section 33-10-196 of the 1976 South Carolina Code, as amended, the undersigned corporation adopts the following Articles of Amendment to its Articles of Incorporation: 1. The name of the Corporation is SOUTH CAROLINA ELECTRIC & GAS COMPANY. 2. On , the corporation adopted the following Amendment(s) of its Articles of Incorporation: NOT APPLICABLE 3. The manner, if not set forth in the amendment, in which any exchange, reclassification, or cancellation of issued shares provided for in the Amendment shall be effected, is as follows: (a) The number of redeemable shares of the Corporation reacquired by redemption or purchase is 1,500 itemized as follows: Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 4.60% 1,500 (b) The aggregate number of issued shares of the Corporation after giving effect to such cancellation is 41,442,626, itemized as follows: Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 5% 125,209 Cumulative Preferred Stock ($50 par value) 4.60% 3,834 Cumulative Preferred Stock ($50 par value) 4.50% 19,088 Cumulative Preferred Stock ($50 par value) 4.60% (Series A) 28,052 Cumulative Preferred Stock ($50 par value) 5.125% 73,000 Cumulative Preferred Stock ($50 par value) 4.60% (Series B) 78,200 Cumulative Preferred Stock ($50 par value) 6% 86,400 Cumulative Preferred Stock ($50 par value) 9.40% 190,245 Cumulative Preferred Stock ($100 par value) 8.12% 126,835 Cumulative Preferred Stock ($100 par value) 7.70% 89,992 Cumulative Preferred Stock ($100 par value) 8.40% 197,668 Cumulative Preferred Stock ($50 par value) 8.72% 127,956 Common Stock ($4.50 par value) 40,296,147 41,442,626 (c) The amount of the stated capital of the Corporation after giving effect to such cancellation is $259,381,361.50. (d) The number of shares which the Corporation has authority to issue after giving effect to such cancellation is 55,502,283, itemized as follows: 71 Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 5% 125,209 Cumulative Preferred Stock ($50 par value) 4.60% 3,834 Cumulative Preferred Stock ($50 par value) 4.50% 19,088 Cumulative Preferred Stock ($50 par value) 4.60% (Series A) 28,052 Cumulative Preferred Stock ($50 par value) 5.125% 73,000 Cumulative Preferred Stock ($50 par value) 4.60% (Series B) 78,200 Cumulative Preferred Stock ($50 par value) 6% 86,400 Cumulative Preferred Stock ($50 par value) 9.40% 190,245 Cumulative Preferred Stock ($100 par value) 8.12% 126,835 Cumulative Preferred Stock ($100 par value) 7.70% 89,992 Cumulative Preferred Stock ($100 par value) 8.40% 197,668 Cumulative Preferred Stock ($50 par value) 8.72% 127,956 Serial Preferred Stock ($50 par value) (1 vote) 449,755 Serial Preferred Stock ($100 par value) (1 vote) 1,335,505 Serial Preferred Stock ($25 par value) (1/4 vote) 2,000,000 Serial Preferred Stock ($50 par value) (1/2 vote) 572,044 Common Stock ($4.50 par value) 50,000,000 55,502,283 4. (a) / / Amendment(s) adopted by shareholder action. At the date of adoption of the amendment, the number of outstanding shares of each voting group entitled to vote separately on the Amendment, and the vote of such shares was: Number of Number of Number of Votes Number of Undisputed Voting Outstanding Votes Entitled Represented at Shares Voted Group Shares to be Cast the meeting For Against (b) / X / The Amendment(s) was duly adopted by the incorporators or board of directors without shareholder approval pursuant to Section 33-6-102(d), 33-10-102 and 33-10-105 of the 1976 South Carolina Code, as amended, and shareholder action was not required. 5. Unless a delayed date is specified, the effective date of these Articles of Amendment shall be the date of acceptance for filing by the Secretary of State (See Section 33-1-230(b)). Date December 9, 1994 SOUTH CAROLINA ELECTRIC & GAS COMPANY By: K. B. Marsh Secretary 72 EX-4 5 Exhibit 3-E STATE OF SOUTH CAROLINA SECRETARY OF STATE ARTICLES OF CORRECTION The following information is submitted pursuant to Section 33- 1-240 of the 1976 South Carolina Code, as amended: 1. The name of the corportion is SOUTH CAROLINA ELECTRIC & GAS COMPANY. 2. That on December 9, 1994, the corporation filed (fill out whichever is applicable): (a) XX The following described document: Articles of Amendment dated December 9, 1994. (b) The attached document (attach copy of the document). 3. That this document was incorrect in the following manner: 3(b) The aggregate number of issued shares of the corporation after giving effect to such cancellation is 41,442,626, consisting of 3,834 shares of 4.60% Cumulative Preferred Stock ($50 par value). 3(c) The amount of the stated capital of the corporation after giving effect to such cancellation is $259,381,361.50. 3(d) The number of shares which the corporation has authority to issue after giving effect to such cancellation is 55,502,283, consisting of 3,834 shares of 4.60% Cumulative Preferred Stock ($50 par value). 4. That the incorrect matters stated in paragraph 3 should be revised as follows: 3(b) The aggregate number of issued shares of the corporation after giving effect to such cancellation is 41,441,126, of which 2,334 are shares of the 4.60% Cumulative Preferred Stock ($50 par value) series. 3(c) The amount of the stated capital of the corporation after giving effect to such cancellation is $259,306,361.50. 3(d) The number of shares which the corporation has authority to issue after giving effect to such cancellation is 55,502,283, of which 2,334 are shares of the 4.60% Cumulative Preferred Stock ($50 par value) series. SOUTH CAROLINA ELECTRIC & GAS COMPANY Date: January 17, 1995 By: Kevin B. Marsh Secretary 73 EX-5 6 Exhibit 3-F STATE OF SOUTH CAROLINA SECRETARY OF STATE ARTICLES OF AMENDMENT Pursuant to Section 33-10-196 of the 1976 South Carolina Code, as amended, the undersigned corporation adopts the following Articles of Amendment to its Articles of Incorporation: 1. The name of the Corporation is SOUTH CAROLINA ELECTRIC & GAS COMPANY. 2. On , the corporation adopted the following Amendment(s) of its Articles of Incorporation: NOT APPLICABLE 3. The manner, if not set forth in the amendment, in which any exchange, reclassification, or cancellation of issued shares provided for in the Amendment shall be effected, is as follows: (a) The number of redeemable shares of the corporation reacquired by redemption or purchase is 8, itemized as follows: Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 7.70% 8 (b) The aggregate number of issued shares of the Corporation after giving effect to such cancellation is 41,441,118, itemized as follows: Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 5% 125,209 Cumulative Preferred Stock ($50 par value) 4.60% 2,334 Cumulative Preferred Stock ($50 par value) 4.50% 19,088 Cumulative Preferred Stock ($50 par value) 4.60% (Series A) 28,052 Cumulative Preferred Stock ($50 par value) 5.125% 73,000 Cumulative Preferred Stock ($50 par value) 4.60% (Series B) 78,200 Cumulative Preferred Stock ($50 par value) 6% 86,400 Cumulative Preferred Stock ($50 par value) 9.40% 190,245 Cumulative Preferred Stock ($100 par value) 8.12% 126,835 Cumulative Preferred Stock ($100 par value) 7.70% 89,984 Cumulative Preferred Stock ($100 par value) 8.40% 197,668 Cumulative Preferred Stock ($50 par value) 8.72% 127,956 Common Stock ($4.50 par value) 40,296,147 41,441,118 (c) The amount of the stated capital of the Corporation after giving effect to such cancellation is $259,305,561.50. (d) The number of shares which the Corporation has authority to issue after giving effect to such cancellation is 55,502,283, itemized as follows: 74 Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 5% 125,209 Cumulative Preferred Stock ($50 par value) 4.60% 2,334 Cumulative Preferred Stock ($50 par value) 4.50% 19,088 Cumulative Preferred Stock ($50 par value) 4.60% (Series A) 28,052 Cumulative Preferred Stock ($50 par value) 5.125% 73,000 Cumulative Preferred Stock ($50 par value) 4.60% (Series B) 78,200 Cumulative Preferred Stock ($50 par value) 6% 86,400 Cumulative Preferred Stock ($50 par value) 9.40% 190,245 Cumulative Preferred Stock ($100 par value) 8.12% 126,835 Cumulative Preferred Stock ($100 par value) 7.70% 89,984 Cumulative Preferred Stock ($100 par value) 8.40% 197,668 Cumulative Preferred Stock ($50 par value) 8.72% 127,956 Serial Preferred Stock ($50 par value) (1 vote) 449,755 Serial Preferred Stock ($100 par value) (1 vote) 1,335,513 Serial Preferred Stock ($25 par value) (1/4 vote) 2,000,000 Serial Preferred Stock ($50 par value) (1/2 vote) 572,044 Common Stock ($4.50 par value) 50,000,000 55,502,283 4. (a) / / Amendment(s) adopted by shareholder action. At the date of adoption of the amendment, the number of outstanding shares of each voting group entitled to vote separately on the Amendment, and the vote of such shares was: Number of Number of Number of Votes Number of Undisputed Voting Outstanding Votes Entitled Represented at Shares Voted Group Shares to be Cast the meeting For Against (b) / X / The Amendment(s) was duly adopted by the incorporators or board of directors without shareholder approval pursuant to Section 33-6-102(d), 33-10-102 and 33-10-105 of the 1976 South Carolina Code, as amended, and shareholder action was not required. 5. Unless a delayed date is specified, the effective date of these Articles of Amendment shall be the date of acceptance for filing by the Secretary of State (See Section 33-1-230(b)). Date January 13, 1995 SOUTH CAROLINA ELECTRIC & GAS COMPANY By: K. B. Marsh Secretary 75 EX-6 7 Exhibit 12 SOUTH CAROLINA ELECTRIC & GAS COMPANY CALCULATION OF BOND RATIO FOR THE YEAR ENDED DECEMBER 31, 1994 (Thousands of Dollars) Net earnings(1) $331,551 Divide by annualized interest charges on: Bonds authenticated under the Company's First and Refunding Mortgage Bond Indenture $42,901 Other indebtedness(1) $51,224 Total annualized interest charges $ 94,125 Bond ratio 3.52 (1) As defined under the Company's First and Refunding Mortgage Bond Indenture (Old Mortgage). 76 SOUTH CAROLINA ELECTRIC & GAS COMPANY CALCULATION OF NEW BOND RATIO FOR THE YEAR ENDED DECEMBER 31, 1994 (Thousands of Dollars) Net earnings(1) $448,766 Divide by annualized interest charges on: Bonds authenticated under the Company's First Mortgage Bond Indenture $49,513 Other indebtedness(1) $43,096 Total annualized interest charges $ 92,609 New Bond Ratio 4.85 (1) As defined under the Company's Collateral Trust Mortgage Indenture (New Mortgage). 77 SOUTH CAROLINA ELECTRIC & GAS COMPANY CALCULATION OF PREFERRED STOCK RATIO FOR THE YEAR ENDED DECEMBER 31, 1994 (Thousands of Dollars) Net Earnings (1) $244,593 Divide by annualized interest charges on: Bonds authenticated under the Company's mortgage bond indentures $ 92,414 Other indebtedness(1) $ 8,432 Preferred Dividend Requirements $ 5,887 Total annualized interest charges $106,733 Preferred stock ratio 2.29 (1) As defined under the Company's Restated Articles of Incorporation. 78 SOUTH CAROLINA ELECTRIC & GAS COMPANY COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES For Each of the Five Years Ended December 31, 1994 (Thousands of Dollars) Year Ended December 31, 1994 1993 1992 1991 1990 Fixed Charges as defined: Interest on long-term debt.................. $ 85,368 $ 77,975 $ 79,452 $ 73,474 $ 67,255 Amortization of debt premium, discount and expense (net).............................. 1,993 1,435 765 776 600 Interest on debt to affiliate............... 279 29 16 830 2,232 Other interest expense...................... 4,910 5,783 6,761 6,260 9,394 Interest component of rentals............... 2,692 2,823 923 885 948 Total Fixed Charges (A)................. $ 95,242 $ 88,045 $ 87,917 $ 82,225 $ 80,429 Earnings, as defined: Income...................................... $152,043 $145,968 $102,163 $122,836 $120,839 Income taxes................................ 82,716 80,738 50,158 67,863 66,389 Total fixed charges above................... 95,242 88,045 87,917 82,225 80,429 Total Earnings (B)...................... $330,001 $314,751 $240,238 $272,924 $267,657 Ratio of Earnings to fixed charges (B/A)...... 3.46 3.57 2.73 3.32 3.33
79 EX-7 8 Exhibit 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Registration Statement No. 33-57955 of South Carolina Electric & Gas Company on Form S-3 of our report dated February 6, 1995 appearing in this Annual Report on Form 10-K of South Carolina Electric & Gas Company for the year ended December 31, 1994. s/Deloitte & Touche LLP DELOITTE & TOUCHE LLP Columbia, South Carolina March 13, 1995 80 EX-8 9 [ARTICLE] OPUR1 [LEGEND] THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 1994 AND THE CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS AND OF CASH FLOWS FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1994 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. [/LEGEND] [PERIOD-TYPE] 12-MOS [FISCAL-YEAR-END] DEC-31-1993 [PERIOD-END] DEC-31-1994 [BOOK-VALUE] PER-BOOK [TOTAL-NET-UTILITY-PLANT] 2,998,132 [OTHER-PROPERTY-AND-INVEST] 11,931 [TOTAL-CURRENT-ASSETS] 253,004 [TOTAL-DEFERRED-CHARGES] 324,024 [OTHER-ASSETS] 0 [TOTAL-ASSETS] 3,587,091 [COMMON] 181,333 [CAPITAL-SURPLUS-PAID-IN] 627,998 [RETAINED-EARNINGS] 324,101 [TOTAL-COMMON-STOCKHOLDERS-EQ] 1,133,432 [PREFERRED-MANDATORY] 49,528 [PREFERRED] 26,027 [LONG-TERM-DEBT-NET] 1,219,991 [SHORT-TERM-NOTES] 130,609 [LONG-TERM-NOTES-PAYABLE] 0 [COMMERCIAL-PAPER-OBLIGATIONS] 0 [LONG-TERM-DEBT-CURRENT-PORT] 33,042 [PREFERRED-STOCK-CURRENT] 2,418 [CAPITAL-LEASE-OBLIGATIONS] 0 [LEASES-CURRENT] 0 [OTHER-ITEMS-CAPITAL-AND-LIAB] 992,044 [TOT-CAPITALIZATION-AND-LIAB] 3,587,091 [GROSS-OPERATING-REVENUE] 1,181,274 [INCOME-TAX-EXPENSE] 84,066 [OTHER-OPERATING-EXPENSES] 866,790 [TOTAL-OPERATING-EXPENSES] 950,856 [OPERATING-INCOME-LOSS] 230,418 [OTHER-INCOME-NET] 7,271 [INCOME-BEFORE-INTEREST-EXPEN] 237,689 [TOTAL-INTEREST-EXPENSE] 85,646 [NET-INCOME] 152,043 [PREFERRED-STOCK-DIVIDENDS] 5,955 [EARNINGS-AVAILABLE-FOR-COMM] 146,088 [COMMON-STOCK-DIVIDENDS] 113,700 [TOTAL-INTEREST-ON-BONDS] 82,980 [CASH-FLOW-OPERATIONS] 211,108 [EPS-PRIMARY] 0 [EPS-DILUTED] 0
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