-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, TlUB0BbygesSVG97aRphiIBKoh5+/fsMsCnKzPSHpsK3G+wJaaITsstBW7tZElG9 YcFEsxRtoPYKH6lodsWQ7A== 0000091882-96-000001.txt : 19960329 0000091882-96-000001.hdr.sgml : 19960329 ACCESSION NUMBER: 0000091882-96-000001 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 6 CONFORMED PERIOD OF REPORT: 19951231 FILED AS OF DATE: 19960328 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: 96540198 BUSINESS ADDRESS: STREET 1: 1426 MAIN ST CITY: COLUMBIA STATE: SC ZIP: 29201 BUSINESS PHONE: 8037483000 MAIL ADDRESS: STREET 1: MAIL CODE 051 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, 1995 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 Section 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 Section 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 8.72% Cumulative Preferred Stock par value $50 per Stock par value $50 share per share 8.12% Cumulative Preferred 7.70% Cumulative Preferred Stock par value $100 Stock par value $100 per share 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 such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x . No . 1 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. [ ] 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 non- affiliates of the registrant as of February 29, 1996 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 29, 1996 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 .......................................... 19 Item 3. Legal Proceedings ................................... 21 Item 4. Submission of Matters to a Vote of Security Holders ................................... 21 PART II Item 5. Market for Registrant's Common Stock and Related Security Holder Matters ................ 21 Item 6. Selected Financial Data ............................. 22 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ...... 23 Item 8. Financial Statements and Supplementary Data ......... 30 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ................ 55 PART III Item 10. Directors and Executive Officers of the Registrant ......................................... 55 Item 11. Executive Compensation .............................. 60 Item 12. Security Ownership of Certain Beneficial Owners and Management .............................. 64 Item 13. Certain Relationships and Related Transactions ...... 65 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ............................ 65 SIGNATURES ........................................................ 66 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 Pipeline Corporation........ South Carolina Pipeline Corporation, an affiliate PRP......................... Potentially Responsible Party PSA......................... The South Carolina Public Service Authority PSC......................... The Public Service Commission of South Carolina PUHCA....................... Public Utility Holding Company Act of 1935, as amended SCANA....................... SCANA Corporation and its 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 3,721 full-time, permanent employees as of December 31, 1995 as compared to 4,009 full-time, permanent employees as of December 31, 1994. SCANA, a South Carolina corporation, was organized in 1984 and is a public utility holding company within the meaning of PUHCA but is presently exempt from registration under such Act. SCANA holds all of the issued and outstanding common stock of the Company. (See Note 1A of Notes to Consolidated Financial Statements.) INDUSTRY SEGMENTS The Company is a regulated public utility engaged in the generation, transmission, distribution and sale of electricity and in the purchase and sale, primarily at retail, of natural gas in South Carolina. The Company also renders urban bus service in the metropolitan areas of Columbia and Charleston, South Carolina. The Company's business is subject to seasonal fluctuations. Generally, sales of electricity are higher during the summer and winter months because of air-conditioning and heating requirements, and sales of natural gas are greater in the winter months due to its use for heating requirements. The Company's electric service area extends into 24 counties covering more than 15,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 30 of the 46 counties in South Carolina and covers more than 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, 1995, 1994 and 1993 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. 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 operates 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. In January 1996 the PSC approved (as discussed under "Capital Requirements and Financing 5 Program") the accelerated recovery of the Company's electric regulatory assets and the shift of depreciation reserves from transmission and distribution assets to nuclear production assets. The Company believes that these actions as well as numerous others that have been and will be taken demonstrate its ability and commitment to succeed in the new operating environment to come. Regulated public utilities are allowed to record as assets some costs that would be expensed by other enterprises. If deregulation or other changes in the regulatory environment occur, the Company may no longer be qualified to apply this accounting treatment and may be required to eliminate such regulatory assets from its balance sheet. Such an event could have a material adverse effect on the Company's results of operations in the period the write-off is recorded. The Company reported on its balance sheet at December 31, 1995 approximately $116 million and $4 million of regulatory assets and liabilities, respectively, excluding amounts related to net accumulated deferred income tax assets of approximately $33 million. CAPITAL REQUIREMENTS AND FINANCING PROGRAM Capital Requirements The cash requirements of the Company arise primarily from its operational needs and its construction program. The ability of the Company to replace existing plant investments, as well as to expand to meet future demand for electricity and gas, will depend upon its ability to attract the necessary 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. On July 10, 1995, the Company filed an application with the PSC for an increase in retail electric rates. On January 9, 1996 the PSC issued an order granting the Company an increase of 7.34% which will produce additional revenues of approximately $67.5 million annually. The increase will be implemented in two phases. The first phase, an increase in revenues of approximately $59.5 million annually based on a test year, or 6.47%, commenced on January 15, 1996. The second phase will be implemented in January 1997 and will produce additional revenues of approximately $8.0 million annually, or .87% more than current rates. The PSC authorized a return on common equity of 12.0%. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million to be collected through rates over a ten-year period. Additionally, the PSC approved accelerated recovery of substantially all (excluding accumulated deferred income taxes) of the Company's electric regulatory assets and the transition obligation for postretirement benefits other than pensions, changing the amortization periods to allow recovery by the end of the year 2000. The Company's request to shift approximately $257 million of depreciation reserves from transmission and distribution assets to nuclear production assets was also approved. The Company's future financial position and results of operations will be affected by its ability to obtain adequate and timely rate and other regulatory relief. (See "Regulation.") During 1996 the Company is expected to meet its capital requirements principally through internally generated funds (approximately 77%, after payment of 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. 6 The Company's estimates of its cash requirements for construction and nuclear fuel expenditures, which are subject to continuing review and adjustment, for 1996 and the four-year period 1997-2000 as now scheduled, are as follows: Type of Facilities 1997-2000 1996 (Thousands of Dollars) Electric Plant: Generation. . . . . . . . . . . . . . . . $268,987 $ 49,036 Transmission. . . . . . . . . . . . . . . 92,502 17,976 Distribution. . . . . . . . . . . . . . . 319,092 64,227 Other . . . . . . . . . . . . . . . . . . 34,152 13,835 Nuclear Fuel. . . . . . . . . . . . . . . . 86,413 21,147 Gas . . . . . . . . . . . . . . . . . . . . 94,147 16,918 Common. . . . . . . . . . . . . . . . . . . 34,089 34,633 Other . . . . . . . . . . . . . . . . . . . 1,511 553 Total . . . . . . . . . . . . . . $930,893 $218,325 The above estimates exclude AFC. Construction The Company's cost estimates for its construction program for the periods 1996 and 1997-2000, 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. Construction of the plant started in November 1992. Commercial operation began in January 1996. The cost of the Cope plant, excluding AFC, is $410.9 million. In addition, the transmission lines for interconnection with the Company's system cost $22.5 million. Approximately $9.8 million of the amounts included in the above table for 1996 relate to the completion of the Cope plant. During 1995 the Company expended approximately $15.9 million as part of a program to extend the operating lives of certain non-nuclear generating facilities. Additional improvements under the program to be made during 1996 are estimated to cost approximately $19.9 million. Additional Capital Requirements In addition to the Company's capital requirements for 1996 described in "Capital Requirements" above, approximately $21.2 million will be required for refunding and retiring outstanding securities and obligations. For the years 1997-2000, the Company has an aggregate of $292.8 million of long-term debt maturing (including approximately $69.2 million for sinking fund requirements, of which $68.7 million may be satisfied by deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits) and $9.8 million of purchase or sinking fund requirements for preferred stock. Actual 1996 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. 7 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 twelve consecutive months out of the fifteen months prior to the month of issuance are at least twice the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 1995 the Bond Ratio was 3.97. The issuance of additional Class A Bonds also is restricted to an additional principal amount equal to (i) 60% of unfunded net property additions (which unfunded net property additions totaled approximately $162.3 million at December 31, 1995), (ii) retirements of Class A Bonds (which retirement credits totaled $64.8 million at December 31, 1995), (iii) and cash on deposit with the Trustee. The Company has placed a new bond indenture (New Mortgage) dated April 1, 1993 covering substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are issued under the New Mortgage on the basis of a like principal amount of Class A Bonds issued under the Old Mortgage which have been deposited with the Trustee of the New Mortgage (of which $185 million were available for such purpose at December 31, 1995), until such time as all presently outstanding Class A Bonds are retired. Thereafter, New Bonds will be issuable on the basis of property additions in a principal amount equal to 70% of the original cost of electric and common plant properties (compared to 60% of value for Class A Bonds under the Old Mortgage), cash deposited with the Trustee, and retirement of New Bonds. New Bonds will be issuable under the New Mortgage only if adjusted net earnings (as therein defined) for twelve consecutive months out of the eighteen months immediately preceding the month of issuance are at least twice the annual interest requirements on all outstanding bonds (including Class A Bonds) and New Bonds to be outstanding (New Bond Ratio). For the year ended December 31, 1995 the New Bond Ratio was 5.31. The following additional financing transaction has occurred since December 31, 1994: On April 12, 1995 the Company issued $100 million of First Mortgage Bonds, 7 5/8% series due April 1, 2025 to repay short-term borrowings. 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 the 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 twelve months or less, but not later than December 31, 1997. The Company had $165 million authorized and unused lines of credit at December 31, 1995. In addition, Fuel Company has a credit agreement for a maximum of $125 million with the full amount available at December 31, 1995. The credit agreement supports the issuance of short-term commercial paper for the financing of nuclear and fossil fuels and sulfur dioxide emission allowances. Fuel Company commercial paper outstanding at December 31, 1995 was $76.8 million. The Company's Restated Articles of Incorporation prohibit issuance of additional shares of preferred stock without consent of the preferred stockholders unless net earnings (as defined therein) for the twelve consecutive months immediately preceding the month of issuance are at least one and one-half times the aggregate of all interest charges and preferred stock dividend requirements (Preferred Stock Ratio). For the year ended December 31, 1995 the Preferred Stock Ratio was 2.58. 8 The ratios of earnings to fixed charges (SEC Method) were 3.41, 3.46, 3.57, 2.73 and 3.32 for the years ended December 31, 1995, 1994, 1993, 1992 and 1991, respectively. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements for the next twelve months and for the foreseeable future. Fuel Financing Agreements The Company has assigned to Fuel Company all of its rights and interests in its various contracts relating to the acquisition and ownership of nuclear and fossil fuels. To finance nuclear and fossil fuels and sulfur dioxide emission allowances, Fuel Company issues, from time to time, commercial paper which is supported, up to $125 million, by an irrevocable revolving credit agreement which expires July 31, 1998. Accordingly, the amounts outstanding have been included in long- term debt. This commercial paper and amounts outstanding under the revolving credit agreement, if any, are guaranteed by the Company. At December 31, 1995 commercial paper outstanding was approximately $76.8 million at a weighted average interest rate of 5.76%. (See Notes 1N and 4 of Notes to Consolidated Financial Statements.) ELECTRIC OPERATIONS Electric Sales In 1995 residential sales of electricity accounted for 43% of electric sales revenues; commercial sales 30%; industrial sales 20%; sales for resale 4%; and all other 3%. KWH sales by classification for the years ended December 31, 1995 and 1994 are presented below: Sales KWH % Classification 1995 1994 Change (thousands) Residential 5,726,815 5,311,139 7.83 Commercial 5,078,185 4,848,620 4.73 Industrial 5,210,368 5,161,717 0.94 Sale for resale 1,063,064 1,024,376 3.78 Other 506,806 494,030 2.59 Total Territorial 17,585,238 16,839,882 4.43 Interchange 195,591 171,046 14.35 Total 17,780,829 17,010,928 4.53 The Company furnishes electricity for resale to three municipalities, four investor-owned utilities, two electric cooperatives and one public power authority. Such sales for resale accounted for 4% of total electric sales revenues in 1995. During 1995 the Company recorded a net increase of 7,943 electric customers, increasing its total customers to 484,381. 9 The electric sales volume increased for the year ended December 31, 1995 compared to the prior year as a result of increased residential and commercial sales due to favorable weather and customer growth. The all-time peak demand of 3,683 MW was set on August 14, 1995. On August 8, 1995 the Company signed an agreement with the DOE to lease the Savannah River Site's (SRS) power and steam generation and transmission facilities. The agreement calls for SRS to purchase all its electrical and a majority of its steam requirements from the Company. The Company will lease (with an option to renew) the power plant for ten years and the electrical transmission lines for 40 years, with an option to refurbish the facilities or build a new system. Electric Interconnections The Company purchases all of the electric generation of Williams Station, owned by GENCO, under a Unit Power Sales Agreement which has been approved by the FERC. Williams Station has a generating capacity of 560 MW. The Company's transmission system is part of the interconnected grid extending over a large part of the southern and eastern portions of the nation. The Company, Virginia Power Company, Duke Power Company, Carolina Power & Light Company, Yadkin, Incorporated and PSA are members of the Virginia- Carolinas Reliability Group, one of the several geographic divisions within the Southeastern Electric Reliability Council. This council provides for coordinated planning for reliability among bulk power systems in the Southeast. The Company is also interconnected with Georgia Power Company, Savannah Electric & Power Company, Oglethorpe Power Corporation and Southeastern Power Administration's Clark Hill Project. Fuel Costs The following table sets forth the average cost of nuclear fuel and coal and the weighted average cost of all fuels (including oil and natural gas) used by the Company and GENCO for the years 1993-1995. 1995 1994 1993 Nuclear: Per million BTU $ .48 $ .51 $ .47 Coal: Company: Per ton $40.01 $39.92 $39.95 Per million BTU 1.57 1.57 1.55 GENCO: Per ton $42.21 $41.85 $41.64 Per million BTU 1.63 1.63 1.62 Weighted Average Cost of All Fuels: Per million BTU $ 1.26 $ 1.39 $ 1.31 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. 10 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 1993-1995 and the estimates for 1996 and 1997. Percent of Total KWH Generated Estimated Actual 1997 1996 1995 1994 1993 Coal 73% 71% 65% 76% 72% Nuclear 24 24 27 17 23 Hydro 3 3 5 6 5 Natural Gas & Oil - 2 3 1 - 100% 100% 100% 100% 100% Coal is used at all five of the Company's major fossil fuel- fired plants and GENCO's Williams Station. Unit train deliveries are used at all of these plants. On December 31, 1995 the Company had approximately a 73-day supply of coal in inventory and GENCO had approximately a 49-day supply. The supply of coal is obtained through contracts and purchases on the spot market. Spot market purchases are expected to continue for coal requirements in excess of those provided by the Company's existing contracts. Contracts for the purchase of coal represent 91.5% of estimated requirements for 1996 (approximately 5.3 million tons, including requirements of Williams Station). The supply of contract coal is purchased from seven suppliers located in eastern Kentucky and southwest Virginia. Contract commitments, which expire at various times from 1997- 2003, approximate 4.85 million tons annually. Sulfur restrictions on the contract coal range from .75% to 2%. The Company believes that its operations are in substantial compliance with all existing regulations relating to the discharge of sulfur dioxide. The Company 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 has adequate supplies of uranium under contract to manufacture nuclear fuel for Summer Station through 2005. The following table summarizes all contract commitments for the stages of nuclear fuel assemblies: Commitment Contractor Regions(1) Term Uranium Energy Resources of Australia 9-13 1990-1997 Uranium Everest Minerals 9-13 1990-1996 Conversion Sequoyah Fuel Corp. 8-12 1989-1995 Enrichment USEC 12-18 1995-2005 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. 11 The Company has on-site spent nuclear fuel storage capability until at least 2009 and expects to be able to expand its storage capacity to accommodate the spent fuel output for the life of the plant through rod consolidation, dry cask storage or other technology as it becomes available. In addition, there is sufficient on-site storage capacity over the life of Summer Station to permit storage of the entire reactor core in the event that complete unloading should become desirable or necessary for any reason. (See "Nuclear Fuel Disposal" under "Environmental Matters" for information regarding the contract with the DOE for disposal of spent fuel.) Decommissioning Decommissioning of Summer Station is presently projected to commence in the year 2022 when the operating license expires. Based on a 1991 study, the expenditures (on a before-tax basis) related to the Company's share of decommissioning activities are estimated, in 2022 dollars assuming a 4.5% annual rate of inflation, to be $545.3 million including partial reclamation costs. The Company is providing for its share of estimated decommissioning costs of Summer Station over the life of Summer Station. The Company's method of funding decommissioning costs is referred to as COMReP (Cost of Money Reduction Plan). Under this plan, funds collected through rates ($3.2 million in each of 1995 and 1994) are used to purchase insurance policies on the lives of certain 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 NRC. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis. The trust's sources of decommissioning funds under the COMReP program include investment components of life insurance policy proceeds, return on investment and the cash transfers from the Company described above. The Company records its liability for decommissioning costs in deferred credits. GAS OPERATIONS Gas Sales In 1995 residential sales accounted for 47% of gas sales revenues; commercial sales 32%; industrial sales 21%. Dekatherm sales by classification for the years ended December 31, 1995 and 1994 are presented below: Sales Dekatherms % Classification 1995 1994 Change Residential 12,333,769 11,531,558 7.0 Commercial 10,436,987 9,813,454 6.4 Industrial 13,467,687 10,938,713 23.1 Transportation gas 3,603,314 5,469,728 (34.1) Total 39,841,757 37,753,453 5.5 During 1995 the Company recorded a net increase of 4,909 gas customers, increasing its total customers to 243,342. 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. 12 The deregulation of natural gas prices at the wellhead and the changes in the prices of natural gas that have occurred under Federal regulation have resulted in the development of a spot market for natural gas in the producing areas of the country. Pipeline Corporation has been successful in purchasing lower cost natural gas in the spot market and arranging for its transportation to South Carolina. 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 the purchase of alternate fuel vehicles on Federal, state, municipal and private fleets. The Company expects these requirements 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, which expire at various times from 1996 to 2003. The volume of gas which Pipeline Corporation is entitled to transport under these contracts on a firm basis is shown below: Maximum Daily Supplier Contract Demand Capacity (MCF) Southern Natural Firm Transportation 184,974 Transco Firm Transportation 29,300 Total 214,274 Under a contract with Pipeline Corporation, the Company's maximum daily contract demand is 224,270 dekatherms. The contract allows the Company to receive amounts in excess of this demand based on availability. The average cost per MCF of natural gas purchased from Pipeline Corporation was approximately $3.77 in 1995 compared to $4.29 in 1994. 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 1,695,489 MCF were in storage at December 31, 1995. 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 of which 4,307,796 MCF were in storage on December 31, 1995. The Company believes that supplies under contract and available for spot market purchase are adequate to meet existing customer demands and to accommodate growth. 13 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 regulation under the Federal Power Act, administered by the FERC and the DOE, in the transmission of electric energy in interstate commerce and in the sale of electric energy at wholesale for resale, as well as with respect to licensed hydroelectric projects and certain other matters, including accounting and the issuance of short-term promissory notes. In the opinion of the Company, it will be able to meet successfully the challenges of the NEPA without any material adverse impact on its results of operations, financial position or business prospects. Federal Energy Regulatory Commission The Company is subject to regulation under the Federal Power Act, administered by the FERC and the DOE, in the transmission of electric energy in interstate commerce and in the sale of electric energy at wholesale for resale, as well as with respect to licensed hydroelectric projects and certain other matters including accounting and the issuance of short-term promissory notes. (See "Capital Requirements and Financing Program.") The Company holds licenses under the Federal Water Power Act or the Federal Power Act with respect to all its hydroelectric projects. The expiration dates of the licenses covering the projects are as follows: Project Capability (KW) License Expiration Date Neal Shoals 5,000 1993 Stevens Creek 9,000 2025 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, applications for new licenses for Neal Shoals and Stevens Creek were filed with the FERC on December 30, 1991. No competing applications were filed. The FERC issued a new 30-year license for the Stevens Creek project on November 22, 1995. The Neal Shoals license application is in the final stage of review. The FERC has issued a Notice of Authorization for Continued Project Operation for Neal Shoals until the FERC acts on the Company's application for a new license. 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 is entitled to be paid its net investment in the project, not to exceed fair value, plus severance damages. 14 The Company has filed an application with the FERC requesting authorization to sell bulk power at market based rates. The application also included proposed open access transmission tariffs. (See "National Energy Policy Act of 1992 and FERC Order 636.") Nuclear Regulatory Commission The Company is subject to regulation by the NRC with respect to the ownership and operation of Summer Station. The NRC's jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. In addition, the Federal Emergency Management Agency is responsible for the review, in conjunction with the NRC, of certain aspects of emergency planning relating to the operation of nuclear plants. For the fourth time in the last five evaluations, Summer Station received a category one rating from the Institute of Nuclear Power Operations (INPO). The category one rating is the highest given by INPO for a nuclear plant's overall operations. National Energy Policy Act of 1992 and FERC Order 636 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 and does not anticipate there to be any material adverse impact on the results of its operations, its financial position or its business prospects. RATE MATTERS The following table presents a summary of significant rate activity for the years 1991-1995 based on test years: REQUESTED GRANTED Date of % % of General Rate Application/ Amount Increase Date of Amount Increase Applications Hearing (Millions) Requested Order (Millions) Granted PSC Electric Retail 07/10/95 $ 76.7 8.4% 1/09/96 $67.5 88% Retail 12/07/92 $ 72.0* 11.4% 6/07/93 $60.5 84% 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. 15 On July 10, 1995, the Company filed an application with the PSC for an increase in retail electric rates. On January 9, 1996 the PSC issued an order granting the Company an increase of 7.34% which will produce additional revenues of approximately $67.5 million annually. The increase will be implemented in two phases. The first phase, an increase in revenues of approximately $59.5 million annually based on a test year, or 6.47%, commenced on January 15, 1996. The second phase will be implemented in January 1997 and will produce additional revenues of approximately $8.0 million annually, or .87% more than current rates. The PSC authorized a return on common equity of 12.0%. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million to be collected through rates over a ten-year period. Additionally, the PSC approved accelerated recovery of substantially all (excluding accumulated deferred income taxes) of the Company's electric regulatory assets and the remaining transition obligation for postretirement benefits other than pensions, changing the amortization periods to allow recovery by the end of the year 2000. The Company's request to shift approximately $257 million of depreciation reserves from transmission and distribution assets to nuclear production assets was also approved. 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 actual and projected site assessment and cleanup costs for the Company's gas operations that had previously been deferred. In October 1995, as a result of the ongoing annual review, the PSC approved the continued use of the billing surcharge. The balance remaining to be recovered amounts to approximately $14.5 million. 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. On May 23, 1995 the Circuit Court ordered the case back to the PSC for reconsideration of several issues including the low-income rider program, routing changes, and the $.75 fare. The Supreme Court declined to review an appeal of the Circuit Court decision and dismissed the case. The PSC filed, along with other intervenors, another Petition for Reconsideration, which the Circuit Court denied. Procedural matters in this case are yet to be resolved in the court. 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 1995 semiannual review of the fuel cost component of electric rates, the PSC decreased the rate from 14.16 mills per KWH to 13.48 mills per KWH, a monthly decrease of $.68 for an average customer using 1,000 KWH a month. For the October 1995 review the PSC continued the rate of 13.48 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 1995 review the PSC decreased the base cost of gas from 51.058 cents per therm to 43.081 cents per therm which resulted in a monthly decrease of $7.98 (including applicable taxes) based on an average of 100 therms per month on a residential bill during the heating season. 16 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. Developments in these areas may require that equipment and facilities be modified, supplemented or replaced. The ultimate effect of these regulations and standards upon existing and proposed operations cannot be forecast. Capital Expenditures In the years 1993 through 1995, capital expenditures for environmental control amounted to approximately $90.0 million. In addition, approximately $10.4 million, $8.8 million and $7.4 million of environmental control expenditures were made during 1995, 1994 and 1993, 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 capitalized expenditures are $10.1 million for 1996 and $138.8 million for the four-year period 1997 through 2000. These expenditures are included in the Company's construction program. 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 had a compliance date of January 1, 1995 and the second, January 1, 2000. The Company's facilities did not require modifications to meet the requirements of Phase I. The Company will most likely meet the Phase II requirements through the burning of natural gas and/or lower sulfur coal in its generating units and the purchase and use of sulfur dioxide emission allowances. Low nitrogen oxide burners are being installed to reduce nitrogen oxide emissions to the levels required by Phase II. Air toxicity regulations for the electric generating industry are likely to be promulgated around the year 2000. The Company filed compliance plans related to Phase II requirements with DHEC by December 31, 1995. The Company currently estimates that air emissions control equipment will require capital expenditures of $113 million over the 1996-2000 period to retrofit existing facilities, with increased operation and maintenance cost of approximately $1 million per year. To meet compliance requirements through the year 2005, the Company anticipates total capital expenditures of approximately $150 million. Water Quality Control The Federal Clean Water Act, as amended, provides for the imposition of effluent limitations that require various levels of treatment for each wastewater discharge. Under this Act, compliance with applicable limitations is achieved under a national permit program. Discharge permits have been issued for all and renewed for nearly all of the Company's and GENCO's generating units. Concurrent with renewal of these permits the permitting agency has implemented a more rigorous control program. The Company has been developing compliance plans to meet this program. Amendments to the Clean Water Act proposed in Congress include several provisions which, if passed, could prove costly to the Company. These include limitations to mixing zones and the implementation of technology-based standards. 17 Superfund Act and Environmental Assessment Program The Company has an environmental assessment program to identify and assess current and former operations sites that could require environmental cleanup. As site assessments are initiated, estimates are made of the cost, if any, to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations; such amounts are deferred and are being amortized and recovered through rates over a ten-year period for electric operations and an eight-year period for gas operations. Deferred amounts totaled $18.0 million and $20.2 million at December 31, 1995 and 1994, respectively. Estimates include, among other items, the costs estimated to be associated with the matters discussed in the following paragraphs. The Company owns four 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. 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 eighteen 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 PRPs have agreed with the EPA to participate in an innovative approach to site investigation and cleanup called "Superfund Accelerated Cleanup Model," allowing the pre-cleanup site investigations process to be compressed significantly. The PRPs have negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study and a corresponding Scope of Work. Field work began in November 1993. 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 operations. The Company has been listed as a PRP and has recorded liabilities, which are not material, for the Macon-Dockery waste disposal site near Rockingham, North Carolina. The Company has participated in de minimis buy-outs for the Aqua-Tech Environmental Inc. site in Greer, South Carolina and a landfill owned by Lexington County in South Carolina. The Company expects to have no further involvement with these two sites. The Arkansas Department of Pollution Control and Ecology 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 the Department has been received. The Company believes that its identification as a PRP was in error, and that the resolution of this issue will not have a material effect on the Company's results of operations or financial position. 18 Solid Waste Control The South Carolina Solid Waste Policy and Management Act of 1991 directed the DHEC to promulgate regulations for the disposal of industrial solid waste. DHEC has promulgated a proposal regulation, which if adopted as a final regulation in its present form, would significantly increase the Company's costs of construction and operation of existing and future ash management facilities. Nuclear Fuel Disposal The Nuclear Waste Policy Act of 1982 requires that the United States government make available by 1998 a permanent repository for high-level radioactive waste and spent nuclear fuel and imposes a fee of 1.0 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 2009 and expects to be able to expand its storage capacity over the life of Summer Station to accommodate the spent nuclear fuel output for the life of the plant through rod consolidation, dry cask storage or other technology as it becomes available. The Act also imposes on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. OTHER MATTERS With regard to the Company's insurance coverage for Summer Station, reference is made to Note 10B of Notes to Consolidated Financial Statements. 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. 19 ELECTRIC The following table gives information with respect to the Company's electric generating facilities. Net Generating Present Year Capability Facility Fuel Capability Location In-Service (KW)(1) Steam Urquhart Coal/Gas Beech Island, SC 1953 250,000 McMeekin Coal/Gas Irmo, SC 1958 252,000 Canadys Coal/Gas Canadys, SC 1962 430,000 Wateree Coal Eastover, SC 1970 700,000 Summer (2) Nuclear Parr, SC 1984 594,000 D-Area (3) Coal DOE Savannah River Site, SC 1995 17,000 Cope (4) Coal Cope, SC 1996 385,000 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 (5) Gas/Oil Parr, SC 1970 60,000 Williams (6) 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 (7) 3,722,000 (1) Summer rating. (2) Represents the Company's two-thirds portion of the Summer Station. (3) This plant is operated under lease from the DOE and is dispatched to DOE's Savannah River Site steam needs. "Net Capacity Rating" for this plant is expected average hourly output. The lease, which may be extended, expires on October 1, 2005. (4) Plant began commercial operation in January 1996. (5) 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. The Company has agreed to purchase the leased turbines on the lease expiration date. (6) The two gas turbines at Williams are leased and have a net capability of 49,000 KW. This lease expires on June 29, 1997. (7) Excludes Williams Station. 20 The Company owns 429 substations having an aggregate transformer capacity of 19,577,868 KVA. The transmission system consists of 3,090 miles of lines and the distribution system consists of 15,596 pole miles of overhead lines and 3,191 trench miles of underground lines. GAS Natural Gas The Company's gas system consists of approximately 6,833 miles of three-inch equivalent distribution pipelines and approximately 11,265 miles of distribution mains and related service facilities. Propane The Company has propane air peak shaving facilities which can supplement the supply of natural gas by gasifying propane to yield the equivalent of 102,000 MCF per day of natural gas. These facilities can store the equivalent of 430,405 MCF of natural gas. TRANSIT The Company owns 98 motor coaches which operate on a route system of 286 miles. ITEM 3. LEGAL PROCEEDINGS For information regarding legal proceedings, see ITEM 1., "BUSINESS - RATE MATTERS" and "BUSINESS - ENVIRONMENTAL MATTERS - Superfund Act and Environmental Assessment Program" 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 1995 and 1994 the Company paid $116.7 million and $115.1 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, 1995 approximately $14.5 million of retained earnings were restricted as to payment of cash dividends on common stock. 21 ITEM 6. SELECTED FINANCIAL DATA For the Years Ended December 31, 1995 1994 1993 1992 1991 Statement of Income Data (Thousands of Dollars except statistics) Operating Revenues $1,211,087 $1,181,274 $1,118,433 $ 994,381 $1,022,342 Operating Income 255,854 230,418 219,319 182,267 196,706 Other Income 9,553 7,271 6,585 3,006 3,283 Net Income 169,185 152,043 145,968 102,163 122,836 Earnings Available for Common Stock 163,498 146,088 139,751 95,689 116,130 Balance Sheet Data Utility Plant, Net $3,157,657 $2,998,132 $2,687,193 $2,503,201 $2,380,761 Total Assets 3,802,433 3,587,091 3,189,939 2,890,953 2,748,580 Capitalization: Common equity 1,315,072 1,133,432 1,051,334 963,741 840,505 Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027 26,027 26,027 26,027 Preferred stock, Net (Subject to purchase or sinking funds) 46,243 49,528 52,840 56,154 59,469 Long-term debt, Net 1,279,379 1,231,191 1,097,043 945,964 993,674 Total Capitalization $2,666,721 $2,440,178 $2,227,244 $1,991,886 $1,919,675 Other Statistics Electric: Customers (Year-End) 484,381 476,438 468,901 461,928 453,687 Territorial Sales (Million KWH) 17,585 16,840 16,889 15,801 15,702 Residential: Average annual use per customer (KWH) 13,859 13,048 14,077 13,037 13,246 Average annual rate per KWH $.0747 $.0743 $.0707 $.0695 $.0700 Gas: Customers (Year-End) 243,342 238,433 221,278 218,582 214,485 Sales (Thousand Therms) 362,384 322,837 267,335 256,495 247,483 Residential: Average annual use per customer (Therms) 570 538 606 577 522 Average annual rate per therm $.82 $.84 $.76 $.74 $.77
22 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. 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, future prices 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 operates 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. In January 1996 the PSC approved (as discussed under "Liquidity and Capital Resources") the accelerated recovery of the Company's electric regulatory assets and the shift of depreciation reserves from transmission and distribution assets to nuclear production assets. The Company believes that these actions as well as numerous others that have been and will be taken demonstrate its ability and commitment to succeed in the new operating environment to come. Regulated public utilities are allowed to record as assets some costs that would be expensed by other enterprises. If deregulation or other changes in the regulatory environment occur, the Company may no longer be eligible to apply this accounting treatment and may be required to eliminate such regulatory assets from its balance sheet. Such an event could have a material adverse effect on the Company's results of operations in the period the write-off is recorded. The Company reported approximately $116 million and $4 million of regulatory assets and liabilities, respectively, excluding amounts related to net accumulated deferred income tax assets of approximately $33 million, on its balance sheet at December 31, 1995. 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 and other regulatory 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. Construction of the plant started in November 1992. Commercial operation began in January 1996. The estimated cost of the Cope plant, excluding AFC, is $410.9 million. In addition, the transmission lines for interconnection with the Company's system are expected to cost $22.5 million. On July 10, 1995 the Company filed an application with the PSC for an increase in retail electric rates. On January 9, 1996 the PSC issued an order granting the Company an increase of 7.34% which will produce additional revenues of approximately $67.5 million annually. The increase will be implemented in two phases. The first phase, an increase in revenues of approximately $59.5 annually based on a test year, or 6.47%, commenced on January 15, 1996. The second phase will be implemented in January 1997 and will produce additional revenues of approximately $8.0 million annually, or .87% more than current rates. The PSC authorized a return on common equity of 12.0%. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million to be collected through rates over a ten-year period. Additionally, the PSC approved accelerated recovery of substantially all of the Company's electric regulatory assets (excluding accumulated deferred income taxes) and the remaining transition obligation for postretirement benefits other than pensions, changing the amortization periods to allow recovery by the end of the year 2000. The Company's request to shift approximately $257 million of depreciation reserves from transmission and distribution assets to nuclear production assets was also approved. 23 The estimated primary cash requirements for 1996, excluding requirements for fuel liabilities and short-term borrowings, (including notes payable to affiliated companies), and the actual primary cash requirements for 1995 are as follows: 1996 1995 (Thousands of Dollars) Property additions and construction expenditures, net of allowance for funds used during construction $197,179 $250,870 Nuclear fuel expenditures 21,147 21,045 Maturing obligations, redemptions and sinking and purchase fund requirements 21,197 15,812 Total $239,523 $287,727 Approximately 45% of total cash requirements (after payment of dividends) was provided from internal sources in 1995 as compared to 22% in 1994. The Company's First and Refunding Mortgage Bond Indenture, dated April 1, 1945 (Old Mortgage), contains provisions prohibiting the issuance of additional bonds thereunder (Class A Bonds) unless net earnings (as therein defined) for twelve consecutive months out of the fifteen months prior to the month of issuance are at least twice the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 1995 the Bond Ratio was 3.97. The issuance of additional Class A Bonds also is restricted to an additional principal amount equal to (i) 60% of unfunded net property additions (which unfunded net property additions totaled approximately $162.3 million at December 31, 1995), (ii) retirements of Class A Bonds (which retirement credits totaled $64.8 million at December 31, 1995), (iii) and cash on deposit with the Trustee. The Company has a new indenture (New Mortgage) dated April 1, 1993 covering substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are issued under the New Mortgage on the basis of a like principal amount of Class A Bonds issued under the Old Mortgage which have been deposited with the Trustee of the New Mortgage (of which $185 million were available for such purpose as of December 31, 1995), until such time as all presently outstanding Class A Bonds are retired. Thereafter, New Bonds will be issuable on the basis of property additions in a principal amount equal to 70% of the original cost of electric and common plant properties (compared to 60% of value for Class A Bonds under the Old Mortgage), cash deposited with the Trustee, and retirement of New Bonds. New Bonds will be issuable under the New Mortgage only if adjusted net earnings (as therein defined) for twelve consecutive months out of the eighteen months immediately preceding the month of issuance are at least twice the annual interest requirements on all outstanding bonds (including Class A Bonds) and New Bonds to be outstanding (New Bond Ratio). For the year ended December 31, 1995 the New Bond Ratio was 5.31. The following financing transaction has occurred since December 31, 1994: On April 12, 1995 the Company issued $100 million of First Mortgage Bonds, 7 5/8% series due April 1, 2025 to repay short-term borrowings. 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 the 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 twelve months or less, but not later than December 31, 1997. The Company had $165 million authorized and unused lines of credit at December 31, 1995. In addition, the Company has a credit agreement for a maximum of $125 million with the full amount available at December 31, 1995. The credit agreement supports the issuance of short-term commercial paper for the financing of nuclear and fossil fuels and sulfur dioxide emission allowances. Fuel Company commercial paper outstanding at December 31, 1995 was $76.8 million. 24 The Company's Restated Articles of Incorporation prohibit issuance of additional shares of preferred stock without consent of the preferred stockholders unless net earnings (as defined therein) for the twelve consecutive months immediately preceding the month of issuance are at least one and one-half times the aggregate of all interest charges and preferred stock dividend requirements (Preferred Stock Ratio). For the year ended December 31, 1995 the Preferred Stock Ratio was 2.58. The Company anticipates that its 1996 cash requirements of $378.9 million will be met through internally generated funds (approximately 77%, after payment of dividends), the sales of additional equity 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 1996 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 for the next twelve months and for the foreseeable future. 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 had a compliance date of January 1, 1995 and the second, January 1, 2000. The Company's facilities did not require modifications to meet the requirements of Phase I. The Company will most likely meet the Phase II requirements through the burning of natural gas and/or lower sulfur coal in its generating units and the purchase and use of sulfur dioxide emission allowances. Low nitrogen oxide burners are being installed to reduce nitrogen oxide emissions to the levels required by Phase II. Air toxicity regulations for the electric generating industry are likely to be promulgated around the year 2000. By December 31, 1995 the Company had filed compliance plans related to Phase II requirements with DHEC. The Company currently estimates that air emissions control equipment will require capital expenditures of $113 million over the 1996-2000 period to retrofit existing facilities, with increased operation and maintenance cost of approximately $1 million per year. To meet compliance requirements through the year 2005, the Company anticipates total capital expenditures of approximately $150 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 SCE&G'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 for this program. Amendments to the Clean Water Act proposed in Congress include several provisions which, if passed, 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 directed DHEC to promulgate regulations for the disposal of industrial solid waste. DHEC has promulgated a proposed regulation which, if adopted as a final regulation in its present form, would significantly increase the Company's and GENCO's costs of construction and operation of existing and future ash management facilities. 25 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, estimates are made of the cost, if any, to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations; such amounts are deferred and are being amortized and recovered through rates over a ten-year period for electric operations and an eight- year period for gas operations. Deferred amounts totaled $18.0 million and $20.2 million at December 31, 1995 and 1994, respectively. Estimates include, among other items, the costs associated with the matters discussed in the following paragraphs. The Company owns four 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 eighteen 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 PRPs have agreed with the EPA to participate in an innovative approach to site investigation and cleanup called "Superfund Accelerated Cleanup Model," allowing the pre-cleanup site investigation process to be compressed significantly. The PRPs have negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study and a corresponding Scope of Work. Field work began in November 1993. 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. Regulatory Matters The Company filed for electric rate relief in 1995 to encompass primarily the remaining costs of completing the Cope Generating Station. As discussed under "Liquidity and Capital Resources," the PSC issued an order on January 9, 1996 increasing electric retail rates. 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 and does not anticipate there to be any material adverse impact on the results of its operations, its financial position or its business prospects. 26 Statements of Financial Accounting Standards To Be Adopted The Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." The provisions of the Statement, which will be implemented by the Company for the fiscal year beginning January 1, 1996, require the recognition of a loss in the income statement and related disclosures whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recoverable. The Company does not believe that adoption of the provisions of the Statement will have a material impact on its results of operations or financial position. The Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123, "Accounting for Stock- Based Compensation," which will be implemented by the Company on January 1, 1996. The Company does not believe that adoption of the provisions of the Statement will have a material impact on its results of operations or financial position. RESULTS OF OPERATIONS Net Income Net income and the percent increase (decrease) from the previous year for the years 1995, 1994 and 1993 were as follows: 1995 1994 1993 Net income $169,185 $152,043 $145,968 Percent increase (decrease) in net income 11.27% 4.16% 42.9% 1995 Net income increased for the year primarily due to increases in electric and gas margins and lower operating and maintenance expenses which more than offset increases in fixed costs. 1994 Net income increased for the year primarily due to an increase in the electric margin which more than offset increases in operating expenses. The Company's financial statements include an allowance for funds used during construction (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 7.9 % of income before income taxes in 1995, 6.3% in 1994 and 5.6% in 1993. 27 Electric Operations Electric sales margins for 1995, 1994 and 1993 were as follows: 1995 1994 1993 (Millions of Dollars) Electric revenues $1,006.6 $974.3 $940.2 (Provision) for rate refunds - 1.2 0.3 Net Electric operating revenues 1,006.6 975.5 940.5 Less: Fuel used in electric generation 177.6 176.6 164.2 Purchased power 98.2 112.9 111.1 Margin $ 730.8 $686.0 $665.2 1995 The electric sales margin increased over the prior year primarily as a result of the combined impact of warmer weather in the third quarter of 1995, colder weather in the fourth quarter of 1995 and the base rate increase received by the Company in mid-1994. These factors more than offset the negative impact of milder weather experienced during the first half of 1995. An increase of 7,943 electric customers to 484,381 total customers contributed to an all-time peak demand record of 3,683 MW set on August 14, 1995. 1994 The electric sales margin increased over the prior year 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. Increases (decreases) from the prior year in megawatt hour (MWH) sales volume by classes were as follows: Classification 1995 1994 Residential 415,676 (339,620) Commercial 229,565 4,198 Industrial 48,651 274,467 Sale for Resale (excluding interchange) 38,688 18,408 Other 12,776 (6,907) Total territorial 745,356 (49,454) Interchange 24,545 (27,013) Total 769,901 (76,467) Gas Operations Gas sales margins for 1995, 1994 and 1993 were as follows: 1995 1994 1993 (Millions of Dollars) Gas operating revenues $200.6 $201.7 $174.0 Less: Gas purchased for resale 125.0 127.8 107.7 Margin $ 75.6 $ 73.9 $ 66.3 1995 The gas sales margin increased over the prior year primarily as a result of increases in interruptible gas sales. 1994 The gas sales margin increased over the prior year primarily as a result of increases in interruptible gas sales. 28 Increases (decreases) from the prior year in dekatherm (DT) sales volume by classes, including transportation gas, were as follows: Classification 1995 1994 Residential 802,211 (477,886) Commercial 623,533 970,726 Industrial 2,528,974 5,057,404 Transportation gas (1,866,414) (1,524,089) Total 2,088,304 4,026,155 Other Operating Expenses and Taxes Increases (decreases) in other operating expenses, including taxes, were as follows: Classification 1995 1994 (Millions of Dollars) Other operation and maintenance $(7.8) $ 3.9 Depreciation and amortization 10.6 5.7 Income taxes 12.9 2.8 Other taxes 5.1 5.0 Total $20.8 $17.4 1995 Other operation and maintenance expenses decreased primarily as a result of lower pension costs and lower costs at electric generating stations. The increase in depreciation and amortization expense primarily is attributable to additions to plant-in-service and the expensing of software costs. The increase in income tax expense corresponds to the increase in operating income. The increase in other taxes reflects higher property taxes resulting from higher millages and assessments partially offset by lower payroll taxes resulting from early retirements of employees. 1994 Other operation and maintenance expenses increased 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 1K 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. Interest Expense Increases (decreases) in interest expense were as follows: Classification 1995 1994 (Millions of Dollars) Interest on long-term debt, net $11.0 $8.0 Other interest expense 4.1 (.6) Total $15.1 $7.4 1995 The increase in interest expense, excluding the debt component of AFC, is due primarily to the issuance of additional debt including commercial paper during the latter part of 1994 and early 1995. 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. 29 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA INDEX TO CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA Page Independent Auditors' Report....................................... 31 Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 1995 and 1994... 32 Consolidated Statements of Income and Retained Earnings for the years ended December 31, 1995, 1994 and 1993............. 34 Consolidated Statements of Cash Flows for the years ended December 31, 1995, 1994 and 1993............................. 35 Consolidated Statements of Capitalization as of December 31, 1995 and 1994................................... 36 Notes to Consolidated Financial Statements..................... 38 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. 30 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, 1995 and 1994 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, 1995. 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, 1995 and 1994 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1995 in conformity with generally accepted accounting principles. s/Deloitte & Touche LLP DELOITTE & TOUCHE LLP Columbia, South Carolina February 7, 1996 31 SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED BALANCE SHEETS December 31, 1995 1994 (Thousands of Dollars) ASSETS Utility Plant (Notes 1, 3 and 4): Electric $3,277,530 $3,165,391 Gas 320,847 307,929 Transit 3,768 3,785 Common 91,616 77,327 Total 3,693,761 3,554,432 Less accumulated depreciation and amortization 1,196,279 1,171,758 Total 2,497,482 2,382,674 Construction work in progress 613,683 571,867 Nuclear fuel, net of accumulated amortization 46,492 43,591 Utility Plant, Net 3,157,657 2,998,132 Nonutility Property and Investments, net of accumulated depreciation (Note 8) 11,603 11,931 Current Assets: Cash and temporary cash investments (Note 8) 6,798 346 Receivables - customer and other 154,816 127,679 Receivables - affiliated companies (Note 1) 7,132 18,121 Inventories (At average cost): Fuel (Notes 1, 3 and 4) 35,812 31,310 Materials and supplies 43,583 43,228 Prepayments 10,158 14,389 Accumulated deferred income taxes 19,420 17,931 Total Current Assets 277,719 253,004 Deferred Debits: Emission allowances 28,514 19,409 Unamortized debt expense 11,445 11,690 Unamortized deferred return on plant investment (Notes 1 and 2) 6,369 10,614 Nuclear plant decommissioning fund (Note 1) 36,070 30,383 Other (Note 1) 273,056 251,928 Total Deferred Debits 355,454 324,024 Total $3,802,433 $3,587,091 32 SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED BALANCE SHEETS December 31, 1995 1994 (Thousands of Dollars) CAPITALIZATION AND LIABILITIES Stockholders' Investment: Common equity (Note 5) $1,315,072 $1,133,432 Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027 Total Stockholders' Investment 1,341,099 1,159,459 Preferred Stock, Net (Subject to purchase or sinking funds)(Notes 6 and 8) 46,243 49,528 Long-Term Debt, Net (Notes 3, 4 and 8) 1,279,379 1,231,191 Total Capitalization 2,666,721 2,440,178 Current Liabilities: Short-term borrowings (Notes 8 and 9) 80,500 100,000 Notes payable - affiliated companies - 19,409 Current portion of long-term debt (Note 3) 36,033 33,042 Current portion of preferred stock (Note 6) 2,439 2,418 Accounts payable 71,731 61,466 Accounts payable - affiliated companies (Notes 1 and 3) 26,212 33,357 Customer deposits 12,518 12,668 Taxes accrued 64,008 46,646 Interest accrued 21,626 21,534 Dividends declared 33,126 28,489 Other 12,507 15,525 Total Current Liabilities 360,700 374,554 Deferred Credits: Accumulated deferred income taxes (Notes 1 and 7) 488,310 503,723 Accumulated deferred investment tax credits (Notes 1 and 7) 78,316 81,546 Accumulated reserve for nuclear plant decommissioning (Note 1) 36,070 30,383 Other (Note 1) 172,316 156,707 Total Deferred Credits 775,012 772,359 Commitments and Contingencies (Note 10) - - Total $3,802,433 $3,587,091 See Notes to Consolidated Financial Statements. 33 SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS For the Years Ended December 31, 1995 1994 1993 (Thousands of Dollars) Operating Revenues (Notes 1 and 2): Electric $1,006,566 $ 975,526 $ 940,547 Gas 200,632 201,746 174,035 Transit 3,889 4,002 3,851 Total Operating Revenues 1,211,087 1,181,274 1,118,433 Operating Expenses: Fuel used in electric generation 177,579 176,581 164,187 Purchased power (including affiliated purchases)(Note 1) 98,231 112,900 111,111 Gas purchased from affiliate for resale (Note 1) 125,032 127,846 107,722 Other operation 211,318 214,344 207,126 Maintenance 53,071 57,801 61,107 Depreciation and amortization (Note 1) 117,584 106,952 101,220 Income taxes (Notes 1 and 7) 96,956 84,066 81,280 Other taxes (Note 12) 75,462 70,366 65,361 Total Operating Expenses 955,233 950,856 899,114 Operating Income 255,854 230,418 219,319 Other Income (Note 1): Allowance for equity funds used during construction 9,499 7,989 7,496 Other income (loss), net of income taxes 54 (718) (911) Total Other Income 9,553 7,271 6,585 Income Before Interest Charges 265,407 237,689 225,904 Interest Charges (Credits): Interest on long-term debt, net 98,361 87,361 79,410 Other interest expense (Notes 1 and 3) 9,324 5,189 5,812 Allowance for borrowed funds used during construction (Note 1) (11,463) (6,904) (5,286) Total Interest Charges, Net 96,222 85,646 79,936 Net Income 169,185 152,043 145,968 Preferred Stock Cash Dividends (At stated rates) (5,687) (5,955) (6,217) Earnings Available for Common Stock 163,498 146,088 139,751 Retained Earnings at Beginning of Year 324,101 291,713 262,262 Common Stock Cash Dividends Declared (Note 5) (121,363) (113,700) (110,300) Retained Earnings at End of Year $ 366,236 $ 324,101 $ 291,713 See Notes to Consolidated Financial Statements. 34 SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1995 1994 1993 (Thousands of Dollars) Cash Flows From Operating Activities: Net income $169,185 $152,043 $145,968 Adjustments to reconcile net income to net cash provided from operating activities: Depreciation and amortization 117,839 107,103 101,370 Amortization of nuclear fuel 20,017 13,487 18,156 Deferred income taxes, net (17,632) 13,133 56,982 Deferred investment tax credits, net (3,230) (2,901) (3,245) Net regulatory asset arising from adoption of SFAS No. 109 13,560 (1,985) (40,398) Allowance for funds used during construction (20,962) (14,893) (12,782) Unamortized loss on reacquired debt (3,325) (129) (17,094) Early retirements (24,823) (7,086) (11,840) Nuclear refueling accrual 6,957 (4,881) (6,086) Over (under) collections, fuel adjustment clause 18,986 (17,965) (13,728) Emission allowances (9,105) (19,409) - Changes in certain current assets and liabilities: (Increase) decrease in receivables (16,148) (26,260) (27,920) (Increase) decrease in inventories (4,857) 26 1,401 Increase (decrease) in accounts payable 3,120 (430) 16,757 Increase (decrease) in estimated rate refunds and related interest - (2,509) (15,302) Increase (decrease) in taxes accrued 17,362 6,681 (11,162) Increase (decrease) in interest accrued 92 3,770 (8,669) Other, net (14,623) 14,106 8,002 Net Cash Provided From Operating Activities 252,413 211,901 180,410 Cash Flows From Investing Activities: Utility property additions and construction expenditures, net of AFC (271,804) (406,054) (287,838) Nonutility property and investments (111) (287) (248) Transfer of assets from SCANA - 6,285 - Net Cash Used For Investing Activities (271,915) (400,056) (288,086) Cash Flows From Financing Activities: Proceeds: Issuance of notes payable - affiliated company - 19,409 - Issuance of mortgage bonds 99,583 99,207 592,884 Issuance of pollution control bonds - 30,000 - Equity contributions from parent 139,505 43,426 58,142 Other long-term debt 2,543 11,200 2,562 Repayments: Notes payable - affiliated company (19,409) - - Mortgage bonds (64,779) - (430,000) Other long-term debt (12,548) (1,662) (405) Preferred stock (3,264) (3,398) (3,295) Dividend Payments: Common stock (116,663) (115,100) (108,641) Preferred stock (5,750) (6,048) (6,247) Short-term borrowings, net (19,500) 98,989 978 Fuel and emission allowance financings, net 26,236 13,844 (18,948) Advances - affiliated companies, net - (1,559) (3,463) Net Cash Provided From Financing Activities 25,954 188,308 83,567 Net Increase (Decrease) in Cash and Temporary Cash Investments 6,452 153 (24,109) Cash and Temporary Cash Investments, January 1 346 193 24,302 Cash and Temporary Cash Investments, December 31 $ 6,798 $ 346 $ 193 Supplemental Cash Flows Information: Cash paid for - Interest (includes capitalized interest of $11,463, $6,904 and $5,286) $105,537 $ 87,255 $ 92,367 - Income taxes 95,827 77,295 79,612 Noncash Financing Activities: Department of Energy decontamination and decommissioning fund obligation - - 4,965 See Notes to Consolidated Financial Statements. 35 SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 1995 1994 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 377,822 238,369 Capital stock expense (5,391) (5,443) Retained earnings 366,236 324,101 Total Common Equity 1,315,072 49% 1,133,432 47% Cumulative Preferred Stock (Not subject to purchase or sinking funds): $100 Par Value - Authorized 200,000 shares $50 Par Value - Authorized 125,209 shares Shares Outstanding Redemption Price Eventual Series 1995 1994 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 1995 1994 Current Through Minimum 7.70% 86,965 89,984 101.00 - 101.00 8,696 8,998 8.12% 123,045 126,835 102.03 - 102.03 12,305 12,684 Total 210,010 216,819 $50 Par Value - Authorized 1,614,405 shares Shares Outstanding Redemption Price Eventual Series 1995 1994 Current Through Minimum 4.50% 17,519 19,088 51.00 - 51.00 876 954 4.60% 834 2,334 50.50 - 50.50 42 117 4.60%(A) 26,052 28,052 51.00 - 51.00 1,303 1,403 4.60%(B) 74,800 78,200 50.50 - 50.50 3,740 3,910 5.125% 72,000 73,000 51.00 - 51.00 3,600 3,650 6.00% 83,200 86,400 50.50 - 50.50 4,160 4,320 8.72% 95,985 127,956 51.00 12-31-98 50.00 4,799 6,398 9.40% 183,219 190,245 51.175 - 51.175 9,161 9,512 Total 553,609 605,275 $25 Par Value - Authorized 2,000,000 shares; None outstanding in 1995 and 1994 Total Preferred Stock (Subject to purchase or sinking funds) 48,682 51,946 Less: Current portion, including sinking fund requirements 2,439 2,418 Total Preferred Stock, Net (Subject to purchase or sinking funds) 46,243 2% 49,528 2% 36 SOUTH CAROLINA ELECTRIC & GAS COMPANY CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 1995 1994 (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 7.70% 2004 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 5/8% 2025 100,000 - First and Refunding Mortgage Bonds: Year of Series Maturity 4 7/8% 1995 - 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 130,771 145,000 8 7/8% 2021 120,450 155,000 Pollution Control Facilities Revenue Bonds: 5.95% Series, due 2003 6,560 6,660 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 30,000 Department of Energy Decontamination and Decommissioning Obligation 3,560 3,922 Commercial Paper 76,830 61,794 Other 3,993 3,294 Total Long-Term Debt 1,319,649 1,269,155 Less: Current maturities, including sinking fund requirements 36,033 33,042 Unamortized discount 4,237 4,922 Total Long-Term Debt, Net 1,279,379 48% 1,231,191 50% Total Capitalization $2,666,721 100% $2,440,178 100% See Notes to Consolidated Financial Statements. 37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: A. Organization and Principles of Consolidation The Company, a public utility, is a South Carolina corporation organized in 1924 and a wholly owned subsidiary of SCANA Corporation (SCANA), a South Carolina holding company. The Company, through wholly owned subsidiaries is predominately engaged in the generation and sale of electricity to wholesale and retail customers in South Carolina and in the purchase, sale and transportation of natural gas to retail customers in South Carolina. The accompanying Consolidated Financial Statements include the accounts of the Company and South Carolina Fuel Company, Inc. (Fuel Company). (See Note 1N.) 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 Pipeline Corporation and at December 31, 1995 and 1994 the Company had approximately $17.5 million and $16.3 million, respectively, payable to Pipeline Corporation for such gas purchases. The Company purchases all of the electric generation of Williams Station, which is owned by GENCO, under a unit power sales agreement. At December 31, 1995 and 1994 the Company had approximately $8.2 million and $8.8 million, respectively, payable to GENCO for unit power purchases. Such unit power purchases, which are included in "Purchased power," amounted to approximately $83.5 million, $92.8 million and $98.1 million in 1995, 1994 and 1993, respectively. Total interest income, based on market interest rates, associated with the Company's advances to affiliated companies was approximately $174,000, $5,000 and $143,000 in 1995, 1994 and 1993, respectively. Included in "Other interest expense" for 1995, 1994 and 1993 is approximately $114,000, $279,000 and $29,000, respectively, relating to advances from affiliated companies. Intercompany interest is calculated at market rates. B. Basis of Accounting The Company prepares its financial statements in accordance with the provisions of Statement of Financial Accounting Standards No. 71 (SFAS 71), "Accounting for the Effects of Certain Types of Regulations." The accounting standard allows cost-based rate-regulated utilities, such as the Company, to recognize in their financial statements revenues and expenses in different time periods than do enterprises that are not rate- regulated. As a result the Company has recorded, as of December 31, 1995, approximately $116 million and $4 million of regulatory assets and liabilities, respectively, excluding net accumulated deferred income tax assets of approximately $33 million. As discussed in Note 2A, the PSC has approved accelerated recovery of substantially all of the Company's electric regulatory assets (approximately $84.8 million). In the future, as a result of deregulation or other changes in the regulatory environment, the Company may no longer meet the criteria for continued application of SFAS 71 and would be required to write off its regulatory assets and liabilities. Such an event could have a material adverse effect on the Company's results of operations in the period the write-off is recorded. C. System of Accounts The accounting records of the Company are maintained in accordance with the Uniform System of Accounts prescribed by the FERC and as adopted by the PSC. 38 D. Utility Plant Utility plant is stated substantially at original cost. The costs of additions, renewals and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged, along with the cost of removal, less salvage, to accumulated depreciation. The costs of repairs, replacements and renewals of items of property determined to be less than a unit of property are charged to maintenance expense. The Company, operator of the Summer Station and PSA are joint owners of Summer Station in the proportions of two-thirds and one-third, respectively. The parties share the operating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant-in-service related to the Company's portion of Summer Station was approximately $925.1 million and $923.1 million as of December 31, 1995 and 1994, respectively. Accumulated depreciation associated with the Company's share of Summer Station was approximately $261.0 million and $297.9 million as of December 31, 1995 and 1994, respectively. (See Note 2A.) The Company's share of the direct expenses associated with operating Summer Station is included in "Other operation" and "Maintenance" expenses. E. Allowance for Funds Used During Construction AFC, a noncash item, reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion of, as a component of construction cost, the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company has calculated AFC using composite rates of 8.6%, 8.5% and 9.4% for 1995, 1994 and 1993, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process and sulfur dioxide emission allowances is capitalized at the actual interest amount. F. 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 1995, 1994 and 1993. G. 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 overcollected through the electric fuel cost component approximately $3.8 million at December 31, 1995 and undercollected approximately $3.5 million at December 31, 1994 which are included in "Deferred Credits - Other" and "Deferral Debits - 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, 1995 and 1994 the Company had undercollected through the gas cost recovery procedure approximately $4.6 million and $16.3 million, respectively, which are included in "Deferred Debits - Other." 39 The Company's gas rate schedules for residential, small commercial and small industrial customers include a weather normalization adjustment, which minimizes fluctuations in gas revenues due to abnormal weather conditions. H. 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 3.02%, 3.01%, and 2.97% for 1995, 1994 and 1993, 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 DOE under a contract for disposal of spent nuclear fuel. I. Nuclear Decommissioning Decommissioning of Summer Station is presently projected to commence in the year 2022 when the operating license expires. Based on a 1991 study, the expenditures (on a before-tax basis) related to the Company's share of decommissioning activities are estimated, in 2022 dollars assuming a 4.5% annual rate of inflation, to be $545.3 million including partial reclamation costs. The Company is providing for its share of estimated decommissioning costs of Summer Station over the life of Summer Station. The Company's method of funding decommissioning cost is referred to as COMReP (Cost of Money Reduction Plan). Under this plan, funds collected through rates ($3.2 million in each of 1995 and 1994) are used to purchase insurance policies on the lives of certain 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. The trust's sources of decommissioning funds under the COMReP program include investment components of life insurance policy proceeds, return on investment and the cash transfers from the Company described above. The Company records its liability for decommissioning costs in deferred credits. 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. Pursuant to the NEPA passed by Congress in 1992, the Company has recorded a liability for its estimated share of amounts required by the DOE for its decommissioning fund. The liability, approximately $3.6 million at December 31, 1995, has been included in "Long-Term Debt, Net." The Company will recover the cost associated with this liability through the fuel cost component of its rates; accordingly, this amount has been deferred and is included in "Deferred Debits - Other." J. Income Taxes The Company is included in the consolidated Federal income tax return filed by SCANA. Income taxes are allocated to the Company based on its contribution to the consolidated total. As required by Statement of Financial Accounting Standards 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. 40 K. 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, 1995, 1994 and 1993 included the following components: 1995 1994 1993 (Thousands of Dollars) Service cost--benefits earned during the period $ 5,187 $ 8,684 $ 7,629 Interest cost on projected benefit obligation 19,473 21,711 20,413 Adjustments: Return on plan assets (103,874) 2,365 (50,389) Net amortization and deferral 74,769 (29,760) 25,936 Amounts contributed by the Company's affiliates (203) (130) (175) Net periodic pension (income) expense $ (4,648) $ 2,870 $ 3,414 The determination of net periodic pension cost is based upon the following assumptions: 1995 1994 1993 Annual discount rate 8.0% 7.25% 8.0% Expected long-term rate of return on plan assets 8.0% 8.0% 8.0% Annual rate of salary increases 2.5% 4.75% 5.5% The following table sets forth the funded status of the plan at December 31, 1995 and 1994: 1995 1994 (Thousands of Dollars) Actuarial present value of benefit obligations: Vested benefit obligation $228,434 $205,364 Nonvested benefit obligation 15,540 13,966 Accumulated benefit obligation $243,974 $219,330 Plan assets at fair value (invested primarily in equity and debt securities) $447,760 $347,702 Projected benefit obligation 284,145 246,318 Plan assets greater than projected benefit obligation 163,615 101,384 Unrecognized net transition liability 9,022 11,307 Unrecognized prior service costs 9,660 9,374 Unrecognized net gain (146,943) (102,284) Pension asset recognized in Consolidated Balance Sheets $ 35,354 $ 19,781 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 1995 and 1994. 1995 1994 Annual discount rate used to determine benefit obligations 7.5% 8.0% Assumed annual rate of future salary increases for projected benefit obligation 3.0% 2.5% 41 The change in the annual discount rate used to determine benefit obligations from 8.0% to 7.5% and the change in the expected salary increase rate from 2.5% to 3.0% as of December 31, 1995 increased the projected benefit obligation and decreased the unrecognized net gain by approximately $28.6 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 $8.5 million and $8.6 million, net of payments to current retirees, for the years ended December 31, 1995 and 1994, respectively. The PSC has authorized accelerated amortization of the Company's remaining transition obligation for postretirement benefits other than pensions related to electric operations. (See Note 2A.) Net periodic postretirement benefit cost for the years ended December 31, 1995, 1994 and 1993, included the following components: 1995 1994 1993 (Thousands of Dollars) Service cost--benefits earned during the period $ 2,076 $ 2,417 $ 1,908 Interest cost on accumulated postretirement benefit obligation 7,253 6,644 5,502 Adjustments: Return on plan assets - - - Amortization of unrecognized transition obligation 3,344 3,344 3,344 Other net amortization and deferral 661 860 - Amounts contributed by the Company's affiliates (610) (575) (525) Net periodic postretirement benefit cost $12,724 $12,690 $10,229 The determination of net periodic postretirement benefit cost is based upon the following assumptions: 1995 1994 1993 Annual discount rate 8.0% 7.25% 8.0% Health care cost trend rate 11.0% 11.25% 13.0% Ultimate health care cost trend rate (to be achieved in 2004) 6.0% 5.25% 6.0% 42 The following table sets forth the funded status of the plan at December 31, 1995 and 1994: 1995 1994 (Thousands of Dollars) Accumulated postretirement benefit obligations for: Retirees $ 64,989 $ 59,174 Other fully eligible participants 6,685 4,995 Other active participants 27,076 24,889 Accumulated postretirement benefit obligation 98,750 89,058 Plan assets at fair value - - Plan assets less accumulated postretirement benefit obligation (98,750) (89,058) Unrecognized net transition liability 58,237 61,581 Unrecognized prior service costs 5,320 3,453 Unrecognized net loss 13,840 11,156 Postretirement benefit liability recognized in Consolidated Balance Sheets $(21,353) $(12,868) The accumulated postretirement benefit obligation is based upon the plan's benefit provisions and the following assumptions: 1995 1994 Assumed health care cost trend rate used to measure expected costs 10.5% 12.0% Ultimate health care cost trend rate (to be achieved in 2004) 5.5% 6.0% Annual discount rate 7.5% 8.0% Annual rate of salary increases 3.0% 2.5% 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, 1995 and the accumulated postretirement benefit obligation as of December 31, 1995 would be to increase such amounts by $203,000 and $3.4 million, respectively. L. 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. M. 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 are 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 $18.0 million and $20.2 million at December 31, 1995 and 1994, respectively, and are included in "Deferred Debits - Other." 43 N. Fuel Inventories Nuclear fuel and fossil fuel inventories and sulfur dioxide emission allowances are purchased and financed by Fuel Company under a contract which requires the Company to reimburse Fuel Company for all costs and expenses relating to the ownership and financing of fuel inventories and sulfur dioxide emission allowances. Accordingly, such fuel inventories and emission allowances and fuel-related assets and liabilities are included in the Company's consolidated financial statements. (See Note 4.) O. Temporary Cash Investments The Company considers temporary cash investments having original maturities of three months or less to be cash equivalents. Temporary cash investments are generally in the form of commercial paper, certificates of deposit and repurchase agreements. P. Recently Issued Accounting Standards The Financial Accounting Standards Board has issued Statement of Financial Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of." The provisions of the Statement, which will be implemented by the Company for the fiscal year beginning January 1, 1996, require the recognition of a loss in the income statement and related disclosures whenever events or changes in circumstances indicate that the carrying amount of a long-lived asset may not be recoverable. The Company does not believe that adoption of the provisions of the Statement will have a material impact on its results of operations or financial position. The Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 123, "Accounting for Stock- Based Compensation," which will be implemented by the Company on January 1, 1996. The Company does not believe that adoption of the provisions of the Statement will have a material impact on its results of operations or financial position. Q. Reclassifications Certain amounts from prior periods have been reclassified to conform with the 1995 presentation. R. Use of Estimates The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimates. 44 2. RATE MATTERS: A. On July 10, 1995, the Company filed an application with the PSC for an increase in retail electric rates. On January 9, 1996 the PSC issued an order granting the Company an increase of 7.34% which will produce additional revenues of approximately $67.5 million annually. The increase will be implemented in two phases. The first phase, an increase in revenues of approximately $59.5 million annually based on a test year, or 6.47%, commenced on January 15, 1996. The second phase will be implemented in January 1997 and will produce additional revenues of approximately $8.0 million annually, or .87% more than current rates. The PSC authorized a return on common equity of 12.0%. The PSC also approved establishment of a Storm Damage Reserve Account capped at $50 million and collected through rates over a ten-year period. Additionally, the PSC approved accelerated recovery of substantially all (excluding accumulated deferred income taxes) of the Company's electric regulatory assets and the transition obligation for postretirement benefits other than pensions, changing the amortization periods to allow recovery by the end of the year 2000. The Company's request to shift approximately $257 million of depreciation reserves from transmission and distribution assets to nuclear production assets was also approved. B. 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. In October 1995, as a result of the ongoing annual review, the PSC approved the continued use of the billing surcharge. The balance remaining to be recovered amounts to approximately $14.5 million. C. In September 1992 the PSC issued an order granting the Company a $.25 increase in transit fares from $.50 to $.75 in both Columbia and Charleston, South Carolina; however, the PSC also required $.40 fares for low-income customers and denied the Company's request to reduce the number of routes and frequency of service. The new rates were placed into effect in October 1992. The Company appealed the PSC's order to the Circuit Court, which on May 23, 1995, ordered the case back to the PSC for reconsideration of several issues including the low-income rider program, routing changes, and the $.75 fare. The Supreme Court declined to review an appeal of the Circuit Court decision and dismissed the case. Another Petition for Reconsideration was filed by the PSC and other intervenors, which was denied by the Circuit Court. Procedural matters in this case are yet to be resolved in the court. 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 1996 through 2000 are summarized as follows: Year Amount Year Amount (Thousands of Dollars) 1996 $ 36,033 1999 $ 17,663 1997 33,252 2000 117,668 1998 114,483 Approximately $17.3 million of the portion of long-term debt payable in 1996 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. 45 The Company has three-year revolving lines of credit totaling $100 million, in addition to other lines of credit, that provide liquidity for issuance of commercial paper. The three- year lines of credit provide back-up liquidity when commercial paper outstanding is in excess of $100 million. The long-term nature of the lines of credit allow commercial paper in excess of $100 million to be classified as long-term debt. The Company had outstanding commercial paper of $111.2 million at December 31, 1994, of which $11.2 million was reclassified to long-term debt. Certain outstanding long-term debt of an affiliated company (approximately $35.9 million at both December 31, 1995 and 1994) 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 and sulfur dioxide emission allowances are financed through the issuance by Fuel Company of short-term commercial paper. These short-term borrowings are supported by an irrevocable revolving credit agreement which expires July 31, 1998. Accordingly, the amounts outstanding have been included in long-term debt. The credit agreement provides for a maximum amount of $125 million that may be outstanding at any time. Commercial paper outstanding totaled $76.8 million and $50.6 million at December 31, 1995 and 1994 at weighted average interest rates of 5.76% and 6.06%, respectively. 5. COMMON EQUITY: The changes in "Stockholders' Investment" (Including Preferred Stock Not Subject to Purchase or Sinking Funds) during 1995, 1994 and 1993 are summarized as follows: Common Preferred Thousands Shares Shares of Dollars 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 49,710 Balance December 31, 1994 40,296,147 322,877 1,159,459 Changes in Retained Earnings: Net Income 169,185 Cash Dividends Declared: Preferred Stock (at stated rates) (5,687) Common Stock (121,363) Equity Contributions from Parent including transfer of assets 139,505 Balance December 31, 1995 40,296,147 322,877 $1,341,099 46 The Restated Articles of Incorporation of the Company and the Indenture underlying its First and Refunding Mortgage Bonds contain provisions that under certain circumstances could limit the payment of cash dividends on common stock. In addition, with respect to hydroelectric projects, the Federal Power Act requires the appropriation of a portion of the earnings therefrom. At December 31, 1995 approximately $14.5 million of retained earnings were restricted by this requirement 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. The aggregate annual amounts of purchase fund or sinking fund requirements for preferred stock for the years 1996 through 2000 are summarized as follows: Year Amount Year Amount (Thousands of Dollars) 1996 $2,439 1999 $2,440 1997 2,440 2000 2,440 1998 2,440 The changes in "Total Preferred Stock (Subject to Purchase or Sinking Funds)" during 1995, 1994 and 1993 are summarized as follows: Number Thousands of Shares of Dollars 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 Shares Redeemed: $100 par value (6,809) (681) $50 par value (51,666) (2,583) Balance December 31, 1995 763,619 $ 48,682 7. INCOME TAXES: Total income tax expense for 1995, 1994 and 1993 is as follows: 1995 1994 1993 (Thousands of Dollars) Current taxes: Federal $ 94,137 $66,597 $60,577 State 14,265 9,505 6,822 Total current taxes 108,402 76,102 67,399 Deferred taxes, net: Federal (7,319) 7,727 12,197 State (603) 2,118 4,387 Total deferred taxes (7,922) 9,845 16,584 Investment tax credits: Amortization of amounts deferred (credit) (3,230) (3,231) (3,245) Total income tax expense $ 97,250 $82,716 $80,738 47 The difference in actual income taxes and the income taxes calculated from the application of the statutory Federal income tax rate (35% for 1995, 1994 and 1993) to pretax income is reconciled as follows: 1995 1994 1993 (Thousands of Dollars) Net income $169,185 $152,043 $145,968 Total income tax expense: Charged to operating expenses 96,956 84,066 81,280 Charged (credited) to other income 294 (1,350) (542) Total pretax income $266,435 $234,759 $226,706 Income taxes on above at statutory Federal income tax rate $ 93,252 $ 82,166 $ 79,347 Increases (decreases) attributable to: Allowance for equity funds used during construction (3,325) (2,796) (2,624) Amortization of deferred return on plant investment 1,486 1,486 1,486 Depreciation differences 3,268 2,994 2,531 Amortization of investment tax credits (3,230) (3,231) (3,245) State income taxes (less Federal income tax effect) 8,880 7,555 7,286 Deferred income tax flowback at higher than statutory rates (3,310) (3,647) (3,641) Other differences, net 229 (1,811) (402) Total income tax expense $ 97,250 $ 82,716 $ 80,738 The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $468.9 million at December 31, 1995 and $485.8 million at December 31, 1994 determined in accordance with Statement No. 109 (see Note 1J) are as follows: 1995 1994 (Thousands of Dollars) Deferred tax assets: Unamortized investment tax credits $ 48,512 $ 50,513 Cycle billing 19,143 17,521 Nuclear operations expenses 3,755 206 Deferred compensation 5,562 5,450 Other postretirement benefits 6,371 3,187 Other 2,929 3,627 Total deferred tax assets 86,272 80,504 Deferred tax liabilities: Property plant and equipment 520,294 533,394 Pension expense 14,191 9,022 Reacquired debt 6,680 7,146 Research and experimentation 6,196 2,276 Other 7,801 14,458 Total deferred tax liabilities 555,162 566,296 Net deferred tax liability $468,890 $485,792 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. 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. 48 8. FINANCIAL INSTRUMENTS: The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 1995 and 1994 are as follows: 1995 1994 Estimated Estimated Carrying Fair Carrying Fair Amount Value Amount Value (Thousands of Dollars) Assets: Cash and temporary cash investments $ 6,798 $ 6,798 $ 346 $ 346 Investments 61 61 61 61 Liabilities: Short-term borrowings 81 81 100,000 100,000 Notes payable - affiliated companies - - 19,409 19,409 Long-term debt 1,315,412 1,412,213 1,264,233 1,195,023 Preferred stock (subject to purchase or sinking funds) 48,682 46,603 51,946 49,348
The information presented herein is based on pertinent information available to the Company as of December 31, 1995 and 1994. 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, 1995, and the current estimated fair value may differ significantly from the estimated fair value at that date. The following methods and assumptions were used to estimate the fair value of the above classes of financial instruments: Cash and temporary cash investments, including commercial paper, repurchase agreements, treasury bills and notes are valued at their carrying amount. Fair values of investments and long-term debt are based on quoted market prices of the instruments or similar instruments, or for those instruments for which there are no quoted market prices available, fair values are based on net present value calculations. Settlement of long term debt may not be possible or may not be a prudent management decision. Short-term borrowings are valued at their carrying amount. The fair value of preferred stock (subject to purchase or sinking funds) is estimated on the basis of market prices. Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been taken into consideration. 49 9. SHORT-TERM BORROWINGS: The Company pays fees to banks as compensation for its committed lines of credit. Commercial paper borrowings are for 270 days or less. Details of lines of credit and short-term borrowings, excluding amounts classified as long-term (Notes 3 and 4), at December 31, 1995, 1994 and 1993 and for the years then ended are as follows: 1995 1994 1993 (Millions of dollars) Authorized lines of credit at year-end $165.0 $165.0 $212.0 Unused lines of credit at year-end $165.0 $165.0 $212.0 Short-term borrowings outstanding at year-end: Commercial paper $ 80.5 $100.0 $ 1.0 Weighted average interest rate 5.83% 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. Construction of the plant started in November 1992. Commercial operation began in January 1996. The cost of the Cope plant, excluding AFC, is $410.9 million. In addition, the transmission lines for interconnection with the Company's system cost $22.5 million. Under the Duke/Fluor Daniel contract the aggregate amount of required minimum payments remaining at December 31, 1995 is $4.2 million due in 1996. Through December 31, 1995 the Company had paid $378.7 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. 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 $1.9 billion for any losses at 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 under the NEIL program. 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 material adverse impact on the Company's financial position and results of operations. 50 C. Environmental As described in Note 1M 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, estimates are made of the cost, if any, to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations; such amounts are deferred and are being amortized and recovered through rates over a ten-year period for electric operations and an eight-year period for gas operations. Such deferred amounts totaled $18.0 million and $20.2 million at December 31, 1995 and 1994, respectively. Estimates to date include, among other items, the costs estimated to be associated with the matters discussed in the following paragraphs. The Company owns four 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 eighteen 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 PRPs have agreed with the EPA to participate in an innovative approach to site investigation and cleanup called "Superfund Accelerated Cleanup Model," allowing the pre-cleanup site investigation process to be compressed significantly. The PRPs have negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study (RI/FS) and a corresponding Scope of Work. Field work began in November 1993. 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. Claims and Litigation The Company is engaged in various claims and litigation incidental to its business operations which management anticipates will be resolved without loss to the Company. No estimate of the range of loss from these matters can currently be determined. 51 11. SEGMENT OF BUSINESS INFORMATION: Segment information at December 31, 1995, 1994 and 1993 and for the years then ended is as follows: 1995 Electric Gas Transit Total (Thousands of Dollars) Operating revenues $1,006,566 $ 200,632 $ 3,889 $1,211,087 Operating expenses, excluding depreciation and amortization 657,452 169,768 10,429 837,649 Depreciation and amortization 103,961 12,616 1,007 117,584 Total operating expenses 761,413 182,384 11,436 955,233 Operating income (loss) $ 245,153 $ 18,248 $ (7,547) 255,854 Add - Other income, net 9,553 Less - Interest charges 96,222 Net income $ 169,185 Capital expenditures: Identifiable $ 245,016 $ 19,670 $ 265 $ 264,951 Utilized for overall Company operations 27,816 Total $ 292,767 Identifiable assets at December 31, 1995: Utility plant, net $2,850,647 $ 209,847 $ 1,878 $3,062,372 Inventories 76,697 2,155 561 79,413 Total $2,927,344 $ 212,002 $ 2,439 3,141,785 Other assets 660,648 Total assets $3,802,433 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, 1994: 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 52 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 53 12. QUARTERLY FINANCIAL DATA (UNAUDITED): 1995 (Thousands of Dollars) First Second Third Fourth Quarter Quarter Quarter Quarter Annual Total operating revenues $308,759 $275,139 $339,937 $287,252 $1,211,087 Operating income 67,189 53,153 87,023 48,489 255,854 Net Income 45,249 30,870 65,040 28,026 169,185 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 54 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 27, 1995 to hold office until the next annual meeting of the Company's stockholders on April 25, 1996. Name and Year First Became Director Age Principal Occupation; Directorships Bill L. Amick 52 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. 54 For more than five years, a partner in (1979) Bookhart Farms, Elloree, SC (general farming). Director, SCANA Corporation, Columbia, SC. William T. Cassels, Jr. 66 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 63 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. 55 Name and Year First Became Director Age Principal Occupation; Directorships James B. Edwards, D.M.D. 68 For more than five years, President and (1986) Professor of Maxillofacial 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; WMX Technologies, Inc., Oak Brook, IL; General Engineering Laboratories, Inc., Charleston SC; GS Industries, Inc., Charlotte, NC; IMO Industries, Inc., Lawrenceville, NJ; National Data Corporation, Atlanta, GA; SCANA Corporation, Columbia, SC. Elaine T. Freeman 60 For more than five years, Executive Director (1992) of ETV Endowment of South Carolina, Inc. (non-profit organization), Spartanburg, SC. Director National Bank of South Carolina, Columbia, SC; SCANA Corporation, Columbia, SC. Lawrence M. Gressette, Jr. 64 For more than five years, Chairman of the (1987) Board and Chief Executive Officer of SCANA Corporation and Chairman of the Board and Chief Executive Officer of all SCANA subsidiaries, including the Company. For more than five years prior to December 13, 1995, President of SCANA Corporation. Director, Wachovia Corporation, Winston- Salem, NC; InterCel, Inc., West Point, GA; The Liberty Corporation, Greenville, SC; SCANA Corporation, Columbia, SC. Benjamin A. Hagood 68 Since January 1, 1993, Chairman of the (1974) Board William M. Bird and Company, Inc., Inc., Charleston, SC (wholesale distributor of floor covering material). For more than two years prior to January 1, 1993, President and Director, William M. Bird and Company, Inc., Charleston, SC. Director, SCANA Corporation, Columbia, SC. 56 Name and Year First Became Director Age Principal Occupation; Directorships W. Hayne Hipp 56 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 53 For more than five years, President and (1991) Chief Operating Officer of the Company. Director, SCANA Corporation, Columbia, SC. F. Creighton McMaster 66 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. 67 For more than five years, President, Fisk (1983) University, Nashville, TN. Director, Suntrust Banks, Inc., Nashville, TN; SCANA Corporation, Columbia, SC. John B. Rhodes 65 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 49 Since December 13, 1995, President of SCANA (1991) Corporation. From May 1, 1994 to December 13, 1995, Executive Vice President of SCANA Corporation. Since August 25, 1993, Assistant Secretary of SCANA Corporation and all of its subsidiaries, including the Company. From August 28, 1991 to February 20, 1996, Chief Financial Officer of the Company. For more than five years prior to May 1, 1994, Senior Vice President of SCANA SCANA Corporation. For more than five years prior to February 20, 1996, Controller of SCANA Corporation. Director, SCANA Corporation, Columbia, SC; InterCel, Inc., West Point, GA. 57 Name and Year First Became Director Age Principal Occupation; Directorships E. Craig Wall, Jr. 58 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; Nationsbank Corp., Charlotte, NC; Blue Cross/Blue Shield of South Carolina, Columbia, SC; SCANA Corporation, Columbia, SC. 58 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) 64 Chairman of the Board and Chief Executive Officer *-present President - SCANA *-1995 B.D. Kenyon (1) 53 President and Chief Operating Officer 1990-present W.B. Timmerman (1) 49 President - SCANA 1995-present President of MPX, an affiliate 1996-present Executive Vice President, 1994-1995 SCANA Assistant Secretary 1993-1996 Chief Financial Officer *-1996 Controller, SCANA *-1996 Senior Vice President, *-1994 SCANA G.J. Bullwinkel, Jr. 47 Senior Vice President- Retail Electric 1995-present Senior Vice President- Fossil & Hydro Production 1993-1994 Senior Vice President- Production 1991-1992 W.A. Darby 50 Senior Vice President - Gas, SCANA Gas Group 1996-present Vice President-Gas Operations *-present President and Treasurer of ServiceCare 1996-present General Manager of ServiceCare, Inc., an affiliate 1994-present J. L. Skolds 45 Senior Vice President - 1994-present Generation Vice President - Nuclear Operations 1990-1994 K. B. Marsh (1) 40 Vice President - Finance, Chief Financial Officer and Controller - SCANA 1996-present Vice President - Finance, Treasurer and Secretary 1992-1996 Vice President - Finance and Treasurer 1991-1992 Vice President - Corporate Planning 1991 Vice President and Controller *-1991 B.T. Zeigler (1) 40 Vice President - SCANA 1996-present General Counsel of SCE&G 1995-present Associate General Counsel - SCE&G Legal Department 1992-1995 Partner - Lewis, Babcock & Hawkins Law Firm *-1992 *Indicates position held at least since March 1, 1991 (1) Also an executive officer of SCANA 59 COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT 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 indicate that no equity securities of the Company are owned by the directors and executive officers. Based solely on a review of the copies of such forms and amendments furnished to the Company and written representations from the executive officers and directors, the Company believes that during 1995 all Section 16(a) filing requirements applicable to its executive officers, directors and greater than 10% beneficial owners were complied with except that one report covering initial ownership of the Company's preferred stock was filed late by Kevin B. Marsh and Belton T. Zeigler. ITEM 11. EXECUTIVE COMPENSATION The following table contains information with respect to compensation paid or accrued during the years 1995, 1994 and 1993 to the Chief Executive Officer of the Company and to each of the other four most highly compensated executive officers of the Company during 1995 who were serving as executive officers of the Company at the end of 1995. SUMMARY COMPENSATION TABLE Name and Principal Year Annual Compensation Long-Term Position Compensation (1) (2) Salary Bonus Other Payouts ($) ($) Annual Compen- sation ($) (3) (4) LTIP All Other Payouts Compensa- ($) tion ($) L. M. Gressette, Jr. 1995 449,246(5) 197,500 65,779 390,156 26,955 Chairman of the 1994 416,609 0 2,255 173,375 24,996 Board and Chief 1993 383,557 186,615 61,699 266,007 23,013 Executive Officer B. D. Kenyon 1995 318,542 104,353 7,107 172,240 19,113 President and Chief 1994 313,581 96,768 2,649 81,619 18,815 Operating Officer 1993 297,760 99,090 4,201 125,792 17,866 W. B. Timmerman 1995 254,214 101,588 987 150,353 15,127 Chief Financial 1994 235,099 19,725 1,323 70,751 14,106 Officer and 1993 220,752 95,738 2,828 109,768 13,245 Assistant Secretary G. J. Bullwinkel 1995 189,097 70,904 487 90,402 11,346 Senior Vice President 1994 170,828 42,573 762 38,249 9,826 - - Retail Electric 1993 148,705 51,975 1,477 58,489 0 J. L. Skolds 1995 176,156 74,151 54 76,128 10,569 Senior Vice President 1994 156,731 42,573 2,146 38,249 9,404 - - Generation 1993 146,438 43,605 4,065 58,489 0 ______________ (1) Payments under the annual Performance Incentive Plan described hereafter. (2) Other annual compensation consists of (i) for Mr. Gressette, perquisites including compensation related to whole life insurance premiums for 1995 in the amount of $54,642, (ii) for Mr. Kenyon, a lump sum payment in lieu of a base salary increase in 1995 and (iii) for all named officers, payments to cover taxes on benefits. (3) Payments under the long-term Performance Share Plan described hereafter. (4) All other compensation consists solely of Company contributions to defined contribution plans based on the funding formula applicable to all employees of the Company. (5) Reflects actual salary paid in 1995. Base salary of $460,000, became effective in May of 1995.
60 Long-Term Performance Share Plan The long-term 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 94 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 annually based primarily on their salary level. In determining award sizes, levels of responsibilities and competitive practices also are considered. Awards under this plan 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 above the 50th percentile of the peer group. 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 threshold payouts of 0.4 times target at the 33rd percentile of three-year performance. Target payouts will be made at the 50th percentile of three-year performance. Maximum payouts will be made at 1.5 times target when SCANA's TSR is at or above the 75th percentile of the peer group. Payments will be made on a sliding scale for performance between threshold and target and target and maximum. No payouts will be earned if performance is 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 1993 through 1995, SCANA's TSR was at the 98th percentile of the PSP Peer Group. This resulted in payouts in February 1996 at 150% of target shares awarded paid in a combination of stock and cash. The following table shows the target awards made in 1995 for potential payment in 1998 under the long-term Performance Share Plan, and estimated future payouts under that plan at threshold, target and maximum levels for the named executive officers. Mr. Gressette's award for the 1995-1997 performance period is prorated to reflect his retirement in February 1997. LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR TARGET AWARDS FOR 1995 TO BE PAID IN 1998 Number of Performance Estimated Future Payouts Under Shares, or Other Non-Stock Price-Based Plans Units or Period Until Other Maturation Name Rights (#) or Payout Threshold Target Maximum ($ or #) ($ or #) ($ or #) L. M. Gressette, Jr. 6,023 1995-1997 2,409 6,023 9,035 B. D. Kenyon 3,700 1995-1997 1,480 3,700 5,550 W. B. Timmerman 3,220 1995-1997 1,288 3,220 4,830 G. J. Bullwinkel 1,940 1995-1997 776 1,940 2,910 J. L. Skolds 1,940 1995-1997 776 1,940 2,910
61 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 Internal Revenue Code ("IRC") maximum benefit limitations. The following table illustrates the estimated maximum annual benefits payable upon retirement at normal retirement date under the Retirement Plan and the SERPs. Pension Plan Table Final Service Years Average Pay 15 20 25 30 35 $150,000 42,311 56,415 70,519 84,623 87,476 200,000 57,311 76,415 95,519 114,623 118,726 250,000 72,311 96,415 120,519 144,623 149,976 300,000 87,311 116,415 145,519 174,623 181,226 350,000 102,311 136,415 170,519 204,623 212,476 400,000 117,311 156,415 195,519 234,623 243,726 450,000 132,311 176,415 220,519 264,623 274,976 500,000 147,311 196,415 245,519 294,623 306,226 550,000 162,311 216,415 270,519 324,623 337,476 600,000 177,311 236,415 295,519 354,623 368,726 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. As of December 31, 1995, Messrs. Gressette, Kenyon, Timmerman, Bullwinkel and Skolds had credited service under the Retirement Plan (or its equivalent under the SERP) of 33, 22, 17, 25 and 10 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, 1996 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 - $113,790; Mr. Kenyon - $122,658; Mr. Timmerman - $129,942; Mr. Bullwinkel - $90,887; and Mr. Skolds - $93,234. 62 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 obli- gated to remain with the Company for six months unless his employment is terminated for disability or normal retirement or until a change in control occurs. Upon a change in control resulting in an officer's termination, the Severance Plan provides for guaranteed severance payments equal to three times the annual compensation of the officer plus payments under certain of the Company's incentive and retirement plans. The officer also would receive an additional amount (a "gross- up" payment) for any IRC Section 4999 excess tax or any such other similar tax applicable to the severance payments. In addition, for 36 months after termination, the officer would receive coverage for medical benefits and life insurance so as to provide the same level of benefits previously enjoyed under group plans or individual policy contracts or otherwise as determined by the Executive Committee of the Board of Directors. Such benefits however would be reduced to the extent that the participant receives similar benefits during the period from another employer. In addition to the Severance Plan, in the event of a merger, consolidation or acquisition in which SCANA is not the surviving corporation, target awards under the Performance Share Plan will become immediately payable based on SCANA's shareholder return performance as of the end of the most recently completed calendar year for each performance period as to which the grant of target shares has occurred at least six months previously. COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION During 1995, no officer, employee or former officer of the Company or its affiliates served as a member of the Long-Term Compensation Committee or the Performance Committee, except Mr. Gressette who served as a member of the Performance Committee. Although Mr. Gressette was an ex-officio, nonvoting member of the Performance Committee during 1995, he did not participate in any of its deliberations concerning executive officer compensation. Since January 1, 1995, the Company has engaged in business transactions with entities with which Mr. Chapman (Chairman of both the Performance Committee and the Long-Term Compensation Committee) and Mr. McMaster (a member of the Long-Term Compensation Committee) are executive officers. Mr. Chapman is Chairman of NationsBank South, a division of NationsBank Corporation. Since January 1, 1995, the Company has 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 affiliates. The amount paid during 1995 by the Company and its affiliates to NationsBank Corporation affiliates on account of such transactions was $3,339,270. It is anticipated that transactions such as described above will continue in the future. Mr. McMaster is the President and Manager of Winnsboro Petroleum Company. Purchases from Winnsboro Petroleum Company totaling $71,413 for fuel oil and gasoline were made during 1995 by the Company and its affiliates. It is anticipated that such purchases will continue in the future. During 1995, there existed one executive officer-director interlock where an executive officer of SCANA Corporation served as a director of another company that had an executive officer serving on one of the SCANA Board of Directors' committees which deals with compensation matters. Mr. Gressette, Chairman of the Board and Chief Executive Officer of the Company, served as a director of The Liberty Corporation and Mr. Hipp, President and Chief Executive Officer of The Liberty Corporation, served as a member of the Company's Long-Term Compensation Committee. 63 Compensation of Directors Fees. During 1995, 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 the Company or its affiliates 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 1995 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 1995. Mr. Cassels became a participant in January 1994 and Mr. Rhodes in July 1987, and interest credited to their deferral accounts during 1995 was $3,591.94 and $19,557.86, respectively. Endowment Plan. Each director participates in the Directors' Endowment Plan, which provides that SCANA 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; any out-of- state designation must be approved by the Performance Committee. The designated institutions are reviewed on an annual basis by the Chief Executive Officer to assure compliance with the intent of the program. The plan is intended to reinforce SCANA's commitment to quality higher education and is intended to enhance SCANA's ability to attract and retain qualified board members. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT All shares of the Company's Common Stock are held, beneficially and of record, by SCANA Corporation. The table set forth below indicates the shares of SCANA's Common Stock beneficially owned as of March 8, 1996 by each director and nominee, each of the executive officers named in the Summary Compensation Table on page 59, 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 2,486 W. Hayne Hipp 2,800 W. B. Bookhart, Jr. 15,761 B. D. Kenyon 18,883 G. J. Bullwinkel 17,255 F. C. McMaster 5,630 W. T. Cassels, Jr. 2,000 Henry Ponder 12,381 H. M. Chapman 6,000 J. B. Rhodes 7,780 J. B. Edwards 4,665 J. L. Skolds 6,414 E. T. Freeman 4,220 W. B. Timmerman 36,459 L. M. Gressette, Jr. 47,493 E. C. Wall, Jr. 14,000 B. A. Hagood 2,370 All directors and executive officers as a group (21 persons) TOTAL 247,243 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 - 480; Mr. Bookhart - 4,498; Mr. Gressette - 1,060; Mr. Hagood - 334; Mr. McMaster - 2,000. Includes shares purchased through December 31, 1995, but not thereafter, by the Trustee under the Savings Plan. 64 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 30. 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 65 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 20, 1996 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 20, 1996 (ii) Principal financial officer: BY (SIGNATURE) s/K. B. Marsh (NAME AND TITLE) K. B. Marsh, Chief Financial Officer DATE February 20, 1996 (iii) Principal accounting officer: BY (SIGNATURE) s/J. E. Addison (NAME AND TITLE) J. E. Addison, Vice President and Controller DATE February 20, 1996 BY (SIGNATURE) s/B. L. Amick (NAME AND TITLE) B. L. Amick, Director DATE February 20, 1996 BY (SIGNATURE) s/W. B. Bookhart, Jr. (NAME AND TITLE) W. B. Bookhart, Jr., Director DATE February 20, 1996 BY (SIGNATURE) s/W. T. Cassels, Jr. (NAME AND TITLE) W. T. Cassels, Jr., Director DATE February 20, 1996 BY (SIGNATURE) s/H. M. Chapman (NAME AND TITLE) H. M. Chapman, Director DATE February 20, 1996 BY (SIGNATURE) s/J. B. Edwards (NAME AND TITLE) J. B. Edwards, Director DATE February 20, 1996 66 BY (SIGNATURE) s/E. T. Freeman (NAME AND TITLE) E. T. Freeman, Director DATE February 20, 1996 BY (SIGNATURE) s/B. A. Hagood (NAME AND TITLE) B. A. Hagood, Director DATE February 20, 1996 BY (SIGNATURE) s/W. Hayne Hipp (NAME AND TITLE) W. Hayne Hipp, Director DATE February 20, 1996 BY (SIGNATURE) s/F. C. McMaster (NAME AND TITLE) F. C. McMaster, Director DATE February 20, 1996 BY (SIGNATURE) s/Henry Ponder (NAME AND TITLE) Henry Ponder, Director DATE February 20, 1996 BY (SIGNATURE) s/W. B. Timmerman (NAME AND TITLE) W. B. Timmerman, Director DATE February 20, 1996 BY (SIGNATURE) s/J. B. Rhodes (NAME AND TITLE) J. B. Rhodes, Director DATE February 20, 1996 BY (SIGNATURE) s/E. C. Wall, Jr. (NAME AND TITLE) E. C. Wall, Jr., Director DATE February 20, 1996 67 SOUTH CAROLINA ELECTRIC & GAS COMPANY Sequentially EXHIBIT INDEX Numbered Number Pages 2. Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession Not Applicable 3. Articles of Incorporation and By-Laws A. Restated Articles of Incorporation of the Company as adopted on December 15, 1993 (Exhibit 3-A to Form 10-Q for the quarter ended June 30, 1994, File No. 1-3375).................... # B. Articles of Amendment, dated June 7, 1994, filed June 9, 1994 (Exhibit 3-B to Form 10-Q for the quarter ended June 30, 1994, File No. 1-3375).... # C. Articles of Amendment, dated November 9, 1994 (Exhibit 3-C to Form 10-K for the year ended December 31, 1994, File No. 1-3375)...................... # D. Articles of Amendment, dated December 9, 1994 (Exhibit 3-D to Form 10-K for the year ended December 31, 1994, File No. 1-3375)...................... # E. Articles of Correction, dated January 17, 1995 (Exhibit 3-E to Form 10-K for the year ended December 31, 1994, File No. 1-3375)...................... # F. Articles of Amendment, dated January 13, 1995 and filed January 17, 1995 (Exhibit 3-F to Form 10-K for the year ended December 31, 1994, File No. 1-3375)......................................... # G. Articles of Amendment dated March 31, 1995 (Exhibit 3-G to Form 10-Q for the quarter ended March 31, 1995, File No. 1-3375)................... # H. Articles of Correction - Amendment to Statement filed March 31, 1995, dated December 13, 1995 (Filed herewith)......................................... 71 I. Articles of Amendment dated December 13, 1995 (Filed herewith)......................................... 72 J. 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 # Incorporated herein by reference as indicated. 68 SOUTH CAROLINA ELECTRIC & GAS COMPANY Exhibit Index (Continued) Sequentially Numbered Number Pages 4. (continued) June 1, 1961 Exhibit 2-K to Registration No. 2-26459 December 1, 1965 Exhibit 2-L to Registration No. 2-26459 June 1, 1966 Exhibit 2-M to Registration No. 2-26459 June 1, 1967 Exhibit 2-N to Registration No. 2-29693 September 1, 1968 Exhibit 4-O to Registration No. 2-31569 June 1, 1969 Exhibit 4-C to Registration No. 33-38580 December 1, 1969 Exhibit 4-Q to Registration No. 2-35388 June 1, 1970 Exhibit 4-R to Registration No. 2-37363 March 1, 1971 Exhibit 2-B-17 to Registration No. 2-40324 January 1, 1972 Exhibit 4-C to Registration No. 33-38580 July 1, 1974 Exhibit 2-A-19 to Registration No. 2-51291 May 1, 1975 Exhibit 4-C to Registration No. 33-38580 July 1, 1975 Exhibit 2-B-21 to Registration No. 2-53908 February 1, 1976 Exhibit 2-B-22 to Registration No. 2-55304 December 1, 1976 Exhibit 2-B-23 to Registration No. 2-57936 March 1, 1977 Exhibit 2-B-24 to Registration No. 2-58662 May 1, 1977 Exhibit 4-C to Registration No. 33-38580 February 1, 1978 Exhibit 4-C to Registration No. 33-38580 June 1, 1978 Exhibit 2-A-3 to Registration No. 2-61653 April 1, 1979 Exhibit 4-C to Registration No. 33-38580 June 1, 1979 Exhibit 4-C to Registration No. 33-38580 April 1, 1980 Exhibit 4-C to Registration No. 33-38580 June 1, 1980 Exhibit 4-C to Registration No. 33-38580 December 1, 1980 Exhibit 4-C to Registration No. 33-38580 April 1, 1981 Exhibit 4-D to Registration No. 33-49421 June 1, 1981 Exhibit 4-D to Registration No. 2-73321 March 1, 1982 Exhibit 4-D to Registration No. 33-49421 April 15, 1982 Exhibit 4-D to Registration No. 33-49421 May 1, 1982 Exhibit 4-D to Registration No. 33-49421 December 1, 1984 Exhibit 4-D to Registration No. 33-49421 December 1, 1985 Exhibit 4-D to Registration No. 33-49421 June 1, 1986 Exhibit 4-D to Registration No. 33-49421 February 1, 1987 Exhibit 4-D to Registration No. 33-49421 September 1, 1987 Exhibit 4-D to Registration No. 33-49421 January 1, 1989 Exhibit 4-D to Registration No. 33-49421 January 1, 1991 Exhibit 4-D to Registration No. 33-49421 February 1, 1991 Exhibit 4-D to Registration No. 33-49421 July 15, 1991 Exhibit 4-D to Registration No. 33-49421 August 15, 1991 Exhibit 4-D to Registration No. 33-49421 April 1, 1993 Exhibit 4-E to Registration No. 33-49421 July 1, 1993 Exhibit 4-D to Registration No. 33-57955 D. Indenture dated as of April 1, 1993 from South Carolina Electric & Gas Company to NationsBank of Georgia, National Association (Filed as Exhibit 4-F to Registration Statement No. 33-49421)......................................... # E. First Supplemental Indenture to Indenture referred to in 4-D dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421)......................... # 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 # Incorporated herein by reference as indicated. 69 SOUTH CAROLINA ELECTRIC & GAS COMPANY Exhibit Index (Continued) Sequentially Numbered Number Pages 12. Statement re Computation of Ratios (Filed herewith)........ 74 13. Annual Report to Security Holders, Form 10-Q or Quarterly Report to Security Holders Not Applicable 16. Letter Re Change in Certifying Accountant Not Applicable 18. Letter Re Change in Accounting Principles Not Applicable 21. Subsidiaries of the Registrant Not Applicable 22. Published Report Regarding Matters Submitted to Vote of Security Holders Not Applicable 23. Consents of Experts and Counsel Consent of Deloitte & Touche LLP.......................... 78 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. 70 EX-1 2 Exhibit 3-H 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 corporation is SOUTH CAROLINA ELECTRIC & GAS COMPANY. 2. That on March 31, 1995, the corporation filed (fill out whichever is applicable): (a) XX The following described document: Articles of Amendment dated March 30, 1995. (b) The attached document (attach copy of the document). 3. That this document was incorrect in the following manner: 3(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: 4. That the incorrect matters stated in Paragraph 3 should be revised as follows: 3(d) The number of shares which the corporation has authority to issue after giving effect to such cancellation is 55,499,083, itemized as follows: SOUTH CAROLINA ELECTRIC & GAS COMPANY Date: December 13, 1995 By: Kevin B. Marsh Secretary 71 EX-2 3 Exhibit 3-I 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 22,960 itemized as follows: Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 4.50% 1,569 Cumulative Preferred Stock ($50 par value) 4.60% 1,500 Cumulative Preferred Stock ($50 par value) 4.60% (Series A) 2,000 Cumulative Preferred Stock ($50 par value) 4.60% (Series B) 3,400 Cumulative Preferred Stock ($50 par value) 5.125% 1,000 Cumulative Preferred Stock ($100 par value) 7.70% 2,759 Cumulative Preferred Stock ($100 par value) 8.12% 3,741 Cumulative Preferred Stock ($50 par value) 9.40% 6,991 (b) The aggregate number of issued shares of the Corporation after giving effect to such cancellation is 41,382,643, 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% 834 Cumulative Preferred Stock ($50 par value) 4.50% 17,519 Cumulative Preferred Stock ($50 par value) 4.60% (Series A) 26,052 Cumulative Preferred Stock ($50 par value) 5.125% 72,000 Cumulative Preferred Stock ($50 par value) 4.60% (Series B) 74,800 Cumulative Preferred Stock ($50 par value) 6% 83,200 Cumulative Preferred Stock ($50 par value) 9.40% 183,219 Cumulative Preferred Stock ($100 par value) 8.12% 123,045 Cumulative Preferred Stock ($100 par value) 7.70% 86,965 Cumulative Preferred Stock ($100 par value) 8.40% 197,668 Cumulative Preferred Stock ($50 par value) 8.72% 95,985 Common Stock ($4.50 par value) 40,296,147 41,382,643 (c) The amount of the stated capital of the Corporation after giving effect to such cancellation is $256,041,361.50. (d) The number of shares which the Corporation has authority to issue after giving effect to such cancellation is 55,489,614, itemized as follows: 72 Class Series No. of Shares Cumulative Preferred Stock ($50 par value) 5% 125,209 Cumulative Preferred Stock ($50 par value) 4.60% 834 Cumulative Preferred Stock ($50 par value) 4.50% 17,519 Cumulative Preferred Stock ($50 par value) 4.60% (Series A) 26,052 Cumulative Preferred Stock ($50 par value) 5.125% 72,000 Cumulative Preferred Stock ($50 par value) 4.60% (Series B) 74,800 Cumulative Preferred Stock ($50 par value) 6% 83,200 Cumulative Preferred Stock ($50 par value) 9.40% 183,219 Cumulative Preferred Stock ($100 par value) 8.12% 123,045 Cumulative Preferred Stock ($100 par value) 7.70% 86,965 Cumulative Preferred Stock ($100 par value) 8.40% 197,668 Cumulative Preferred Stock ($50 par value) 8.72% 95,985 Serial Preferred Stock ($50 par value) (1 vote) 456,781 Serial Preferred Stock ($100 par value) (1 vote) 1,342,322 Serial Preferred Stock ($25 par value) (1/4 vote) 2,000,000 Serial Preferred Stock ($50 par value) (1/2 vote) 604,015 Common Stock ($4.50 par value) 50,000,000 55,489,614 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) / XX / 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 share- holder 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 13, 1995 SOUTH CAROLINA ELECTRIC & GAS COMPANY By: K. B. Marsh Secretary 73 EX-12 4 Exhibit 12 SOUTH CAROLINA ELECTRIC & GAS COMPANY CALCULATION OF BOND RATIO FOR THE YEAR ENDED DECEMBER 31, 1995 (Thousands of Dollars) Net earnings(1) $377,720 Divide by annualized interest charges on: Bonds authenticated under the Company's First and Refunding Mortgage Bond Indenture $37,774 Other indebtedness(1) $57,260 Total annualized interest charges $ 95,034 Bond ratio 3.97 (1) As defined under the Company's First and Refunding Mortgage Bond Indenture (Old Mortgage). 74 SOUTH CAROLINA ELECTRIC & GAS COMPANY CALCULATION OF NEW BOND RATIO FOR THE YEAR ENDED DECEMBER 31, 1995 (Thousands of Dollars) Net earnings(1) $503,940 Divide by annualized interest charges on: Bonds authenticated under the Company's First Mortgage Bond Indenture $94,912 Other indebtedness(1) $ - Total annualized interest charges $ 94,912 New Bond Ratio 5.31 (1) As defined under the Company's Collateral Trust Mortgage Indenture (New Mortgage). 75 SOUTH CAROLINA ELECTRIC & GAS COMPANY CALCULATION OF PREFERRED STOCK RATIO FOR THE YEAR ENDED DECEMBER 31, 1995 (Thousands of Dollars) Net Earnings (1) $276,870 Divide by annualized interest charges on: Bonds authenticated under the Company's mortgage bond indentures $94,912 Other indebtedness(1) $ 6,621 Preferred Dividend Requirements $ 5,629 Total annualized interest charges $107,162 Preferred stock ratio 2.58 (1) As defined under the Company's Restated Articles of Incorporation. 76 SOUTH CAROLINA ELECTRIC & GAS COMPANY COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES For Each of the Five Years Ended December 31, 1995 (Thousands of Dollars) Year Ended December 31, 1995 1994 1993 1992 1991 Fixed Charges as defined: Interest on long-term debt.................. $ 96,138 $ 85,368 $ 77,975 $ 79,452 $ 73,474 Amortization of debt premium, discount and expense (net).............................. 2,223 1,993 1,435 765 776 Interest on debt to affiliate............... 114 279 29 16 830 Other interest expense...................... 9,210 4,910 5,783 6,761 6,260 Interest component of rentals............... 2,771 2,692 2,823 923 885 Total Fixed Charges (A)................. $110,456 $ 95,242 $ 88,045 $ 87,917 $ 82,225 Earnings, as defined: Income...................................... $169,185 $152,043 $145,968 $102,163 $122,836 Income taxes................................ 97,249 82,716 80,738 50,158 67,863 Total fixed charges above................... 110,456 95,242 88,045 87,917 82,225 Total Earnings (B)...................... $376,890 $330,001 $314,751 $240,238 $272,924 Ratio of Earnings to fixed charges (B/A)...... 3.41 3.46 3.57 2.73 3.32
77 EX-23 5 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 7, 1996 appearing in this Annual Report on Form 10-K of South Carolina Electric & Gas Company for the year ended December 31, 1995. s/Deloitte & Touche LLP DELOITTE & TOUCHE LLP Columbia, South Carolina March 28, 1996 78 EX-27 6
UT THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATED BALANCE SHEET AS OF DECEMBER 31, 1995 AND THE CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS AND OF CASH FLOWS OF THE TWELVE MONTHS ENDED DECEMBER 31, 1995 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. 12-MOS DEC-31-1995 DEC-31-1995 PER-BOOK 3,157,657 11,603 277,719 355,454 0 3,802,433 181,333 767,503 366,236 1,315,072 46,243 26,027 1,279,379 80,500 0 0 36,033 2,439 0 0 1,016,740 3,802,433 1,211,087 96,956 858,277 955,233 255,854 9,553 265,407 96,222 169,185 5,687 163,498 121,363 90,539 252,413 0 0
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