-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: keymaster@town.hall.org Originator-Key-Asymmetric: MFkwCgYEVQgBAQICAgADSwAwSAJBALeWW4xDV4i7+b6+UyPn5RtObb1cJ7VkACDq pKb9/DClgTKIm08lCfoilvi9Wl4SODbR1+1waHhiGmeZO8OdgLUCAwEAAQ== MIC-Info: RSA-MD5,RSA, UW1TDJtqROAIArVCTVxyBMhPFTyn5VdSy+rA9DAY9zNfzwLXKPJz3MrCnBe16fGR Wo7CB3ewnL9QVAyFgqwENg== 0000754737-95-000002.txt : 19950615 0000754737-95-000002.hdr.sgml : 19950615 ACCESSION NUMBER: 0000754737-95-000002 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 5 CONFORMED PERIOD OF REPORT: 19941231 FILED AS OF DATE: 19950310 SROS: NONE FILER: COMPANY DATA: COMPANY CONFORMED NAME: SCANA CORP CENTRAL INDEX KEY: 0000754737 STANDARD INDUSTRIAL CLASSIFICATION: 4931 IRS NUMBER: 570784499 STATE OF INCORPORATION: SC FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-08809 FILM NUMBER: 95519853 BUSINESS ADDRESS: STREET 1: 1426 MAIN ST STREET 2: P O BOX 764 CITY: COLUMBIA STATE: SC ZIP: 29201 BUSINESS PHONE: 8037483000 MAIL ADDRESS: STREET 1: MAIL CODE 073 CITY: COLUMBIA STATE: SC ZIP: 29218 10-K 1 SECURITIES AND EXCHANGE COMMISSION WASHINGTON, DC 20549 FORM 10-K (Mark One) x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED] For the fiscal year ended December 31, 1994 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED] For the transition period from to Commission File Number 1-8809 SCANA CORPORATION (Exact name of registrant as specified in its charter) SOUTH CAROLINA 57-0784499 (State or other jurisdiction of (IRS employer incorporation or organization) identification no.) 1426 MAIN STREET, COLUMBIA, SOUTH CAROLINA 29201 (Address of principal executive offices) (Zip code) Registrant's telephone number, including area code (803) 748-3000 Securities registered pursuant to 12(b) of the Act: Title of each class Name of each exchange on which registered Common Stock, without par value New York Stock Exchange Securities registered pursuant to 12(g) of the Act: None (Title of class) 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 Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [X] State the aggregate market value of the voting stock held by non-affiliates of the registrant. The aggregate market value shall be computed by reference to the price at which the stock was sold, or the average bid and asked prices of such stock, as of a specified date within 60 days prior to the date of filing. (See definition of affiliate in Rule 405.) Note: If a determination as to whether a particular person or entity is an affiliate cannot be made without involving unreasonable effort and expense, the aggregate market value of the common stock held by non-affiliates may be calculated on the basis of assumptions reasonable under the circumstances, provided that the assumptions are set forth in this form. The aggregate market value of the voting stock held by nonaffiliates of the registrant was $2,132,604,581 at February 28, 1995 based on the closing price of the Common Stock on such date, as reported by the New York Stock Exchange composite tape in The Wall Street Journal. 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. The total number of shares of the registrant's Common Stock, no par value, outstanding at February 28, 1995 was 48,330,982. 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). (1) Specified sections of the Registrant's 1995 Proxy Statement, dated March 17, 1995, in connection with its 1995 Annual Meeting of Stockholders, are incorporated by reference in Part III hereof. 2 TABLE OF CONTENTS Page DEFINITIONS ....................................................... 4 PART I Item 1. Business ............................................ 5 Item 2. Properties .......................................... 21 Item 3. Legal Proceedings ................................... 23 Item 4. Submission of Matters to a Vote of Security Holders ................................... 23 Corporate Structure .......................................... 24 Executive Officers of the Registrant ......................... 25 PART II Item 5. Market for Registrant's Common Stock and Related Security Holder Matters ................ 26 Item 6. Selected Financial Data ............................. 27 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ...... 29 Item 8. Financial Statements and Supplementary Data ......... 38 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ............. 66 PART III Item 10. Directors and Executive Officers of the Registrant ......................................... 66 Item 11. Executive Compensation .............................. 66 Item 12. Security Ownership of Certain Beneficial Owners and Management .............................. 66 Item 13. Certain Relationships and Related Transactions ...... 66 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K ............................ 67 SIGNATURES ........................................................ 68 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..................... SCANA Corporation and its subsidiaries 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 DRP......................... SCANA Corporation Dividend Reinvestment and Stock Purchase Plan EPA......................... United States Environmental Protection Agency FERC........................ United States Federal Energy Regulatory Commission Fuel Company................ South Carolina Fuel Company, Inc. GENCO....................... South Carolina Generating Company, Inc. Hydrocarbons................ SCANA Hydrocarbons, Inc. KVA......................... Kilovolt-ampere KW.......................... Kilowatt KWH......................... Kilowatt-hour LNG......................... Liquefied Natural Gas MCF......................... Thousand Cubic Feet MW.......................... Megawatt NEPA........................ National Energy Policy Act of 1992 NRC......................... United States Nuclear Regulatory Commission Peoples..................... Peoples Natural Gas Company of South Carolina Petroleum Resources......... SCANA Petroleum Resources, Inc. Pipeline Corporation........ South Carolina Pipeline Corporation PSA......................... The South Carolina Public Service Authority PSC......................... The Public Service Commission of South Carolina PUHCA....................... Public Utility Holding Company Act of 1935 SCANA....................... SCANA Corporation, the parent company SCE&G....................... South Carolina Electric & Gas Company SEC......................... United States Securities and Exchange Commission Southern Natural............ Southern Natural Gas Company SPSP........................ SCANA Corporation Stock Purchase-Savings Plan Suburban.................... Suburban Propane Group, Inc. 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 SCANA, a South Carolina corporation having general business powers, was incorporated on October 10, 1984 and is a public utility holding company within the meaning of PUHCA but is exempt from registration under such Act (see Regulation). SCANA has its principal executive office at 1426 Main Street, Columbia, South Carolina 29201, telephone number (803) 748-3000. SCANA holds all the capital stock of each of its subsidiaries except for the Preferred Stock of SCE&G and the capital stock of SCANA's indirect, wholly owned subsidiaries which are not material individually or in the aggregate. SCANA and its subsidiaries had 4,575 full-time, permanent employees as of December 31, 1994 as compared to 4,788 full-time, permanent employees as of December 31, 1993. SEGMENTS OF BUSINESS SCANA neither owns nor operates any physical properties. It currently has 12 direct, wholly owned subsidiaries which are engaged in the functionally distinct operations described below. Regulated Utilities The Company's principal subsidiary, SCE&G, 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. SCE&G also renders urban bus service in the metropolitan areas of Columbia and Charleston, South Carolina. SCE&G'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. SCE&G's electric service area extends into 24 counties covering more than 15,000 square miles in the central, southern and southwestern portions of South Carolina. The service area for natural gas encompasses all or part of 29 of the 46 counties in South Carolina and covers more than 20,000 square miles. The total population of counties representing the combined service area is approximately 2.3 million. The predominant industries in the territories served by SCE&G 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. GENCO owns and operates Williams Station and sells electricity solely to SCE&G. Fuel Company acquires, owns and provides financing for SCE&G's nuclear fuel, fossil fuel and sulfur dioxide emission allowance requirements. Pipeline Corporation is engaged in the purchase, transmission and sale of natural gas on a wholesale basis to distribution companies and directly to industrial customers in 39 counties throughout South Carolina. Pipeline Corporation owns LNG liquefaction and storage facilities. It also supplies the natural gas for SCE&G's gas distribution system. Other resale customers include municipalities and county gas authorities and gas utilities. The industrial customers of Pipeline Corporation are primarily engaged in the manufacturing or processing of ceramics, paper, metal, food and textiles. 5 Nonregulated Businesses Petroleum Resources owns and/or operates oil and gas properties in 12 states and Federal waters offshore Texas, Louisiana and Alabama. Hydrocarbons markets natural gas and light hydrocarbons. It also owns and operates an 80 million gallon underground propane storage cavern near York, South Carolina and a 62 mile, six-inch propane pipeline that connects the cavern facility with Dixie Pipeline Company near Bethune, South Carolina. The cavern leases storage space to industries, utilities and propane suppliers. Hydrocarbons also owns and operates the Wilburton Gathering System in Oklahoma. Suburban Propane purchases, delivers and sells propane. In 1994 Suburban sold approximately 23 million gallons of propane and had approximately 32,000 residential, commercial and industrial customers at year end. MPX Systems, Inc. is involved in telecommunications-related ventures providing fiber optic telecommunications, video conferencing and specialized mobile radio services. Having installed over 2,000 miles of fiber optic cable in South Carolina, Georgia, Alabama, Mississippi, Louisiana and Texas, MPX has, in addition, recently begun efforts in video conferencing and the establishment of a Specialized Mobile Radio system in South Carolina and is also pursuing Personal Communication Services licenses for wireless communications in the Southeast. In January 1994 the Company signed an agreement to sell substantially all of the real estate assets of SCANA Development Corporation to Liberty Properties Group, Inc. of Greenville, South Carolina for $91.5 million. On March 4, 1994 the Company and Liberty amended the agreement to exclude certain projects then under construction, and the sales price was reduced to $49.6 million. The transaction was closed on May 27, 1994. Certain other assets of SCANA Development Corporation are being sold to other parties. These transactions did not have a material impact on the Company's financial position or results of operations. ServiceCare, Inc. is engaged in providing energy related products and services beyond the energy meter. Its primary business is providing homeowners with service contracts on their home appliances. At year end, ServiceCare had approximately 16,000 customers. Primesouth, Inc. is engaged in power plant management and maintenance services. SCANA Capital Resources, Inc. has provided equity capital for diversified investments. Information with respect to major segments of business for the years ended December 31, 1994, 1993 and 1992 is contained in Note 11 of the Notes to Consolidated Financial Statements and all such information is incorporated herein by reference. COMPETITION The electric utility industry has begun a major transition that could lead to expanded market competition and less regulatory protection. The transition began with the enactment of the Public Utility Regulatory Policies Act of 1978 which facilitated the entry of competitors into the electric generation business. Subsequently, NEPA was enacted in 1992 to promote competition among utility and nonutility generators in the wholesale electric generation market. Recent initiatives in some states to lessen regulation and promote competition, particularly with regard to retail transmission access, also have accelerated the utility industry's transition. Future deregulation of electric wholesale and retail markets will create opportunities to compete for new and existing customers and markets. As a result, profit margins and asset values of some utilities could be adversely affected. 6 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, SCE&G, reorganized its operations around Strategic Business Units. Maintaining a competitive cost structure is of paramount importance in the utility's strategic plan. SCE&G has undertaken a variety of initiatives, including reductions in operation and maintenance costs and in staffing levels. SCE&G 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. CAPITAL REQUIREMENTS AND FINANCING PROGRAM Capital Requirements The cash requirements of the Company arise primarily from SCE&G's operational needs, the Company's construction program and the need to fund the activities or investments of the Company's nonregulated subsidiaries. The ability of the Company's regulated subsidiaries to replace existing plant investment, as well as to expand to meet future demand for electricity and gas, will depend upon their ability to attract the necessary financial capital on reasonable terms. The Company's regulated subsidiaries recover 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 regulated subsidiaries expand their construction programs, 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 the regulated subsidiaries' ability to obtain adequate and timely rate relief. As discussed in Note 2B of Notes to Consolidated Financial Statements, on June 7, 1993 the PSC issued an order granting SCE&G a 7.4% annual increase in retail electric rates which was implemented in two phases over a two year period: phase one, effective June 1993, producing $42.0 million annually, and phase two, effective June 1994, producing $18.5 million annually, based on a test year. During 1995 the Company is expected to meet its capital requirements principally through internally generated funds (approximately 42%, excluding dividends), sales of additional shares of common stock including sales pursuant to the DRP and SPSP, and the issuance and sale of debt securities. Short-term liquidity is expected to be provided primarily by issuance of commercial paper. The timing and amount of such sales and the type of securities to be sold will depend upon market conditions and other factors. The Company's estimates of its cash requirements for construction (excluding potential oil and gas investments) and nuclear fuel expenditures, which are subject to continuing review and adjustment, for 1995 and the four-year period 1996-1999 as now scheduled, are as follows: Type of Facilities 1996-1999 1995 (Thousands of Dollars) South Carolina Electric & Gas Company: Electric Plant: Generation . . . . . . . . . . . . . . $ 388,193 $129,825 Transmission . . . . . . . . . . . . . 92,701 25,928 Distribution . . . . . . . . . . . . . 295,571 67,283 Other. . . . . . . . . . . . . . . . . 69,322 16,874 Nuclear Fuel. . . . . . . . . . . . . . . 68,171 23,084 Gas . . . . . . . . . . . . . . . . . . . 60,415 18,895 Transit . . . . . . . . . . . . . . . . . 1,012 432 Common . . . . . . . . . . . . . . . . . 35,090 25,342 Nonutility . . . . . . . . . . . . . . . 580 175 Total . . . . . . . . . . . . . . . . . 1,011,055 307,838 Other Companies Combined. . . . . . . . . . 214,960 63,530 Total . . . . . . . . . . . $1,226,015 $371,368 The above estimates exclude AFC. 7 Construction The Company's cost estimates for its construction program for the periods 1995 and 1996-1999, shown in the above table, include costs of the projects described below. SCE&G entered into a contract with Duke/Fluor Daniel in 1991 to design, engineer and build a 385 MW coal-fired electric generating plant near Cope, South Carolina in Orangeburg County. Construction of the plant began in November 1992 and is expected to be complete in late 1995 with commercial operation beginning in early 1996. The estimated cost of the Cope plant, excluding financing costs and allowance for funds used during construction (AFC) but including an allowance for escalation, is $450 million. In addition, the transmission lines for interconnection with SCE&G's system are expected to cost $26 million. Until completion of the new plant, SCE&G is contracting for additional power as necessary to ensure that the energy demands of its customers can be met. The steam generators at Summer Station were replaced in late 1994 during the regularly scheduled refueling outage. The replacement was completed in 38 days, a new U.S. record and only one day off the world record for a steam generator replacement. The new steam generators are expected to result in shorter, less costly refueling outages, and greater electricity output is expected to result from less required maintenance. During 1994 SCE&G and GENCO expended approximately $11.4 million as part of a program to extend the operating lives of certain generating facilities. Additional improvements to be made under the program during 1995 are estimated to cost approximately $15.0 million. Additional Capital Requirements In addition to the Company's capital requirements for 1995 described above, approximately $25.6 million will be required for refunding and retiring outstanding securities and obligations. For the years 1996-1999, the Company has an aggregate of $338.3 million of long-term debt maturing (including approximately $59.4 million for sinking fund requirements, of which $59.0 million may be satisfied by deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits) and $9.8 million of purchase or sinking fund requirements for preferred stock. Actual 1995 expenditures may vary from the estimates set forth above due to factors such as inflation, economic conditions, regulation, legislation, rates of load growth, environmental protection standards and the cost and availability of capital. Financing Program The Company has in effect a medium-term note program for the issuance from time to time of unsecured medium-term debt securities. The proceeds from the sales of these securities may be used to fund additional business activities in nonutility subsidi- aries, to reduce short-term debt incurred in connection therewith or for general corporate purposes. In December 1994, a shelf registration statement filed with the Securities and Exchange Commission became effective, providing for the issuance of up to an additional $250 million in medium-term notes. At December 31, 1994 the Company had available for issuance $317.6 million under this program. SCE&G's First and Refunding Mortgage Bond Indenture, dated April 1, 1945 (Old Mortgage), contains provisions prohibiting the issuance of additional bonds thereunder (Class A Bonds) unless net earnings (as therein defined) for 12 consecutive months out of the 15 months prior to the month of issuance are at least twice the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 1994 the Bond Ratio was 3.52. The issuance of additional Class A Bonds is restricted also to an additional principal amount equal to 60% of unfunded net property additions (which unfunded net property additions totaled approximately $499.8 million at December 31, 1994), Class A Bonds issued on the basis of retirements of Class A Bonds (no retirement credits remained at December 31, 1994) and Class A Bonds issued on the basis of cash on deposit with the Trustee. 8 SCE&G has placed a new bond indenture (New Mortgage) dated April 1, 1993 on substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are expected to be issued under the New Mortgage on the basis of a like principal amount of Class A Bonds issued under the Old Mortgage, which have been deposited with the Trustee of the New Mortgage (of which $57 million were available for such purpose at December 31, 1994), until such time as all presently outstanding Class A Bonds are retired. Thereafter, New Bonds will be issuable on the basis of property additions in a principal amount equal to 70% of the original cost of electric and common plant properties (compared to 60% of value for Class A Bonds under the Old Mortgage), cash deposited with the Trustee, and retirement of New Bonds. New Bonds will be issuable under the New Mortgage only if adjusted net earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice the annual interest requirements on all outstanding bonds (including Class A Bonds) and New Bonds to be outstanding (New Bond Ratio). For the year ended December 31, 1994 the New Bond Ratio was 4.85. The following additional financing transactions have occurred since December 31, 1993: , On January 14, 1994 the Company closed unsecured bank loans totaling $60 million, due January 13, 1995, and used the proceeds to pay off a loan in a like total amount. In January 1995 the Company refinanced the loans with an unsecured bank loan of $60 million due January 12, 1996 at an initial interest rate of 6.44%, subject to reset quarterly at LIBOR plus ten basis points. , On July 21, 1994 SCE&G issued $100 million of First Mortgage Bonds, 7.70% series due July 15, 2004 to repay short-term borrowings in a like amount. , On November 3, 1994 SCE&G issued $30 million of Pollution Control Facilities Revenue Bonds due November 1, 2024. The proceeds from the sale of the bonds are being used to defray the cost of constructing certain facilities for the disposal of solid waste at SCE&G's Cope Generating Station under construction in Orangeburg County, South Carolina. Without the consent of at least a majority of the total voting power of SCE&G's preferred stock, SCE&G 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 SCE&G'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, SCE&G and GENCO must obtain FERC authority to issue short-term debt. The FERC has authorized SCE&G to issue up to $200 million of unsecured promissory notes or commercial paper with maturity dates of 12 months or less but not later than December 31, 1997. GENCO has not sought such authorization. The Company had $479.1 million authorized lines of credit and had unused lines of credit of $455.1 million at December 31, 1994. In addition SCE&G has a credit agreement for a maximum of $75 million to finance nuclear and fossil fuel inventories with $24.4 million available at December 31, 1994. SCE&G's Restated Articles of Incorporation prohibit issuance of additional shares of preferred stock without consent of the preferred stockholders unless net earnings (as defined therein) for the 12 consecutive months immediately preceding the month of issuance are at least one and one-half times the aggregate of all interest charges and preferred stock dividend requirements (Preferred Stock Ratio). For the year ended December 31, 1994 the Preferred Stock Ratio was 2.29. On December 16, 1994 the Company registered with the SEC 2,000,000 additional shares of the Company's common stock to be issued and sold under the SPSP. During 1994 the Company issued 595,438 shares of the Company's common stock under the DRP. In addition, the Company issued 781,354 shares of its common stock pursuant to its SPSP. The Company has authorized and reserved for issuance, and registered under effective registration statements, 1,470,386 and 2,091,066 shares of common stock pursuant to the DRP and the SPSP, respectively. 9 In January 1994 the Company signed an agreement to sell substantially all of the real estate assets of SCANA Development Corporation to Liberty Properties Group, Inc. of Greenville, South Carolina for $91.5 million. On March 4, 1994 the Company and Liberty amended the agreement to exclude certain projects then under construction, and the sales price was reduced to $49.6 million. The transaction was closed on May 27, 1994. Certain other assets of SCANA Development Corporation are being sold to other parties. These transactions did not have a material impact on the Company's financial position or results of operations. MPX Systems Inc., a wholly owned subsidiary of SCANA, through a joint venture with ITC Transmission Systems, a Georgia-based telecommunications holding company, is constructing a fiber optic network through Texas, Louisiana, Mississippi, Alabama and Georgia. The network, which will consist of more than 900 miles of fiber optic lines, is expected to be completed by June 1995 at a cost of $58 million. In addition, MPX is pursuing Personal Communication Services licenses for wireless communications in the Southeast through a joint venture with ITC Personal Communications, Inc., Intercel PCS Services, Inc., and South Atlantic PCS Corporation. A $40 million construction loan obtained by the joint venture has been guaranteed in part by SCANA Corporation. All new ventures currently capitalize on fiber infrastructure in place and provide for expansion of the network. The ratio of earnings to fixed charges (SEC method) was 3.02, 3.41, 2.79, 3.24 and 4.07 for the years ended December 31, 1994, 1993, 1992, 1991 and 1990 respectively. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements. Fuel Financing Agreements SCE&G has assigned to Fuel Company all of its rights and interests in its various contracts relating to the acquisition and ownership of nuclear and fossil fuel. To finance nuclear and fossil fuel, Fuel Company issues, from time to time, its promissory notes with maturities of less than 270 days ("Commercial Paper"). The issuance of Commercial Paper is supported by an irrevocable revolving credit agreement which expires July 31, 1996. Accordingly, the amounts outstanding have been included in long- term debt. Fuel Company's Commercial Paper and amounts outstanding under the revolving credit agreement, if any, are guaranteed by SCE&G. The credit agreement provides for a maximum amount of $75 million that may be outstanding at any time. At December 31, 1994 Commercial Paper outstanding for nuclear and fossil fuel inventories was approximately $50.6 million at a weighted average interest rate of 6.06%. Such fuel inventories and fuel-related assets and liabilities are included in the Company's financial statements (See Note 4 of Notes to Consolidated Financial Statements). ELECTRIC OPERATIONS Electric Sales In 1994 residential sales of electricity accounted for 42% of electric sales revenues; commercial sales 30%; industrial sales 21%; sales for resale 4%; and all other 3%. KWH sales by classification for the years ended December 31, 1994 and 1993 are presented below: Sales KWH % Classification 1994 1993 Change (thousands) Residential 5,311,139 5,650,753 (6.01) Commercial 4,846,619 4,835,492 0.23 Industrial 5,161,717 4,887,121 5.62 Sale for resale 1,024,376 1,005,968 1.83 Other 494,030 500,937 (1.38) Total Territorial 16,837,881 16,880,271 (0.25) Interchange 171,046 198,059 (13.64) Total 17,008,927 17,078,330 (0.41) 10 SCE&G furnishes electricity for resale to three municipalities, three investor-owned utilities, two electric cooperatives and one public power authority. Such sales for resale accounted for 4% of SCE&G's total electric sales revenues in 1994. During 1994 the Company recorded a net increase of 7,538 electric customers, increasing its total customers to 476,412. The electric sales volume decreased for the year ended December 31, 1994 compared to the corresponding period as a result of decreased residential kilowatt-hour sales and interchange power delivered due to milder weather in 1994. The peak demand of 3,444 MW was recorded on January 19, 1994. The all-time record of 3,557 MW was set on July 29, 1993. Electric Interconnections SCE&G's transmission system is part of the interconnected grid extending over a large part of the southern and eastern portion of the nation. SCE&G, Virginia Power Company, Duke Power Company, Carolina Power & Light Company, Yadkin, Incorporated and PSA are members of the Virginia-Carolinas Reliability Group, one of the several geographic divisions within the Southeastern Electric Reliability Council which provides for coordinated planning for reliability among bulk power systems in the Southeast. SCE&G 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 for the years 1992-1994. 1994 1993 1992 Nuclear: Per million BTU $ .51 $ .47 $ .52 Coal: Per ton $40.43 $40.48 $40.45 Per million BTU 1.59 1.57 1.57 Weighted Average Cost of All Fuels: Per million BTU $ 1.39 $ 1.32 $ 1.27 The fuel costs shown above exclude the effects of a PSC approved offsetting of fuel costs through the application of credits carried on SCE&G's books as a result of a 1980 settlement of certain litigation. Fuel Supply The following table shows the sources and approximate percentages of total KWH generation by each category of fuel for the years 1992-1994 and the estimates for 1995 and 1996. Percent of Total KWH Generated Actual Estimated 1994 1993 1992 1996 1995 Coal 77% 72% 65% 72% 69% Nuclear 17 22 29 23 26 Hydro 6 5 5 5 5 Natural Gas & Oil - 1 1 - - 100% 100% 100% 100% 100% Coal is currently used at all four of SCE&G's major fossil fuel-fired plants and GENCO's Williams Station. Unit train deliveries are used at all of these plants. On December 31, 1994 SCE&G had approximately a 74-day supply of coal in inventory and GENCO had approximately a 68-day supply. 11 The supply of coal is obtained through contracts and purchases on the spot market. Spot market purchases are expected to continue for coal requirements in excess of those provided by the Company's existing contracts. Contracts for the purchase of coal represent the following percentages of estimated requirements for 1995 (approximately 5.1 million tons) and expire at the dates indicated (giving effect to the Company's potential to exercise renewal options): Range of % of Initial Final No. of Tons % of 1995 Sulfur Content Expiration Expiration Per Year Requirement per Contract Date (1) Date (1) 482,500 9.5 1.1-1.5 02/28/1996 02/29/2000 359,500 7.0 1.0-1.8 12/31/1996 12/31/2002 562,500 11.0 1.1-2.0 03/31/1997 03/31/2003 144,000 2.8 1.0-1.6 04/30/1995 04/30/1997 981,000 19.2 up to 1.5 12/31/1996 12/31/2002 732,170 14.4 0.75-1.75 04/30/1997 04/30/2003 425,000 8.3 0.8-1.5 06/30/1995 06/30/1999 3,686,670 72.2 (1) Contract extensions beyond the initial expiration date are subject to mutual agreement on price, terms, quantity and quality. All of the above contracts, except the contracts expiring on April 30, 1995 and June 30, 1995 which have firm prices, are subject to periodic price adjustments based on changes in indices published by the U. S. Department of Labor. Coal purchased in December 1994 had an average sulfur content of 1.26%, which permitted SCE&G and GENCO to comply with existing environmental regulations. The Company believes that SCE&G's and GENCO's 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 Control Matters"). SCE&G currently has adequate supplies of uranium under contract to manufacture nuclear fuel for Summer Station through 1997. The following table summarizes all contract commitments for the stages of nuclear fuel assemblies: Commitment Contractor Regions(1) Term Uranium Energy Resources of Australia 9-13 1990-1996 Uranium Everest Minerals 9-13 1990-1996 Conversion Sequoyah Fuel Corp. 8-12 1989-1995 Enrichment USEC (2) Through 2022 Fabrication Westinghouse 1-21 1982-2009 Reprocessing None (1) A region represents approximately one-third to one-half of the nuclear core in the reactor at any one time. Region no. 11 was loaded in 1994 and Region no. 12 will be loaded in 1996. (2) The contract with the USEC is a "requirements" type contract whereby the USEC supplies total enrichment requirements for the unit through the year 2022, as specified by its then current schedule. SCE&G has on-site spent fuel storage capability until at least 2008 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 Control Matters" for information regarding the contract with the DOE for disposal of spent fuel.) 12 GAS OPERATIONS Gas Sales In 1994 residential sales accounted for 29% of gas sales revenues; commercial sales 19%; industrial sales 38%; sales for resale 14%. Dekatherm sales by classification for the years ended December 31, 1994 and 1993 are presented below: SALES DEKATHERMS % CLASSIFICATION 1994 1993 CHANGE Residential 11,531,558 12,651,000 (8.9) Commercial 9,886,622 9,611,556 (0.3) Industrial 41,513,880 30,335,059 36.9 Sale for resale 15,178,820 19,144,130 (20.7) Transportation gas 16,067,294 29,542,805 (45.6) Total 94,178,174 101,284,550 (7.3) During 1994 the Company recorded a net increase of 3,878 customers, increasing its total customers to 238,614. The demand for gas is affected by conservation, the weather, the price relationship between gas and alternate fuels and other factors. The deregulation of natural gas prices at the wellhead which took place on January 1, 1985 and the changes in the prices of natural gas that have occurred under Federal regulation have resulted in the development of a spot market for natural gas in the producing areas of the country. Pipeline Corporation has been successful in purchasing lower cost natural gas in the spot market and arranging for its transportation to South Carolina. Pipeline Corporation has also negotiated contracts with certain direct and indirect industrial customers for the transportation of natural gas that the industrial customers purchase directly from suppliers. 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 Company's gas subsidiaries are positioned for the related market changes arising from this order. Pipeline Corporation, operating wholly within the State of South Carolina, provides natural gas utility service, including transportation services, for its customers, and supplies natural gas to SCE&G and other wholesale purchasers. Hydrocarbons acquires and sells natural gas in the newly deregulated markets. Petroleum Resources owns natural gas reserves that supply natural gas for the interstate markets. Neither Hydrocarbons nor Petroleum Resources supplies natural gas to any affiliate for use in providing regulated gas utility services. To reduce dependence on imported oil, NEPA imposes purchase requirements for alternate fuel vehicles for Federal, state, municipal and private fleets which increase over a period of years. The Company expects these requirements for alternate fuel vehicles to develop business opportunities for the sale of compressed natural gas as fuel for vehicles, but it cannot predict the magnitude of this new market. 13 Gas Cost and Supply Pipeline Corporation purchases natural gas under contracts with producers and marketers on a short-term basis at current price indices and on a long-term basis for reliability assurance at index prices plus a gas inventory charge. The gas is brought to South Carolina through transportation agreements with both Southern Natural and Transco. The volume of gas which Pipeline Corporation is entitled to transport through these contracts on a firm basis is shown below: Maximum Daily Supplier Contract Demand Capacity (MCF) Southern Natural Firm Transportation 188,000 Transco Firm Transportation 29,300 Total 217,300 Additional natural gas volumes are brought to Pipeline Corporation's system as capacity is available for interruptible transportation. During 1994 the average cost per MCF of natural gas purchased for resale, including spot market purchases, was approximately $2.00 compared to approximately $2.42 during 1993. To meet the requirements of 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 liquefied equivalent of 1,900,000 MCF of natural gas, of which approximately 1,524,833 MCF were in storage at December 31, 1994. On peak days the LNG plants can regasify up to 150,000 MCF per day. Additionally, Pipeline Corporation had contracted for 6,450,727 MCF of natural gas storage space on December 31, 1994, of which 4,550,847 MCF were in storage at such date. The Company believes that current supplies under contract and spot market purchases of natural gas are adequate to meet existing customer demands for service and to accommodate growth. Curtailment Plans The FERC has established allocation priorities applicable to firm and interruptible capacities on interstate pipeline companies which require Southern Natural and Transco to allocate capacity to Pipeline Corporation. The FERC allocation priorities are not applicable to deliveries by Pipeline Corporation to its customers, which are governed by a separate curtailment plan approved by the PSC. Gas Reserves Petroleum Resources is actively involved in oil and natural gas exploration, development and production activities. It currently owns and/or operates oil and gas properties in Texas, Louisiana, Mississippi, Oklahoma, California, Arkansas, Nebraska, Kansas, New Mexico, Alabama, Utah, Wyoming and Federal waters offshore Texas, Louisiana and Alabama. Gas Marketing Hydrocarbons markets natural gas as well as other light hydrocarbons. Hydrocarbons also owns and operates the Wilburton Gathering System in Oklahoma. Propane Operations Suburban purchases, delivers and sells propane. In 1994 Suburban sold approximately 23 million gallons of propane and had approximately 32,000 residential, commercial and industrial customers at year end. Hydrocarbons owns and operates an 80 million gallon under- ground propane storage facility that leases storage space to industrial companies, utilities and others. It also owns and operates a 62 mile propane pipeline connected to the Dixie Pipeline System which traverses central South Carolina. 14 REGULATION General SCANA is a public utility holding company within the meaning of PUHCA, but is exempt under Section 3(a)(1) of PUHCA from regulation by the SEC as a registered holding company unless and until the SEC shall otherwise order, except for Section 9(a)(2) thereof prohibiting the acquisition of securities of other public utilities without a prior order of the SEC. SCE&G 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. National Energy Policy Act of 1992 Congress has passed NEPA, the principal thrust of which is to create a more competitive wholesale power supply market by creating "exempt wholesale generators" (EWGs) designated by the FERC, which are independent power producers (IPPs) whose owners will not become holding companies under PUHCA. Upon application of a wholesaler of electric energy, the FERC may order any electric utility that owns transmission facilities used for wholesale sales of electric energy to provide transmission service (including any enlargement of transmission capacity needed to provide the service) to the applicant. Charges for transmission service must be "just and reasonable" and a utility is entitled to recover "all legitimate, verifiable economic costs" incurred in connection with any transmission service so ordered. The FERC may not order such service where it (1) would "unreasonably impair the continued reliability of electric wheeling" judged by reference to "consistently applied regional or national reliability standards, guidelines or criteria;" (2) would result in "retail wheeling;" or (3) would conflict with state laws governing retail marketing areas of electric utilities. Electric utilities, including exempt and non-exempt holding companies, may own and operate EWGs subject to advance approval by state utility commissions, which are given access to books and records of the EWG and its affiliates to the extent that such a commission requires access to perform its regulatory duties. It allows both registered and exempt utility holding companies to acquire interests in foreign utility companies engaged in the generation, transmission or distribution of electricity or the retail distribution of gas, where a state commission has certified that it has the ability to protect the utility's retail ratepayers against adverse investments in foreign utilities by affiliates of public utilities that such commissions regulate. State commissions must consider rate making changes and other regulatory reform to ensure that electric utilities' investments in energy efficiency and demand side management programs are at least as profitable as investing in new generating capacity. FERC has issued a Notice of Proposed Rule Making to develop regulations under NEPA concerning EWGs and electric transmission service. NEPA also has provisions concerning nuclear power, alternate fuel vehicles, minimum efficiency standards, integrated resource planning, demand side management incentives, a variety of energy research projects relating to environmental measures, electric and magnetic fields, hydroelectric projects, and global warming. It authorizes one step licensing for nuclear power plants and requires EPA to issue standards for the Yucca Mountain repository site for nuclear waste (see "Nuclear Fuel Disposal" under "Environmental Control Matters"). To reduce dependence on imported oil, NEPA imposes purchase requirements for alternate fuel vehicles for federal, state, municipal and private fleets which increase over a period of years (see "Gas Operations"). The Company's regulated business operations are likely to be impacted by the NEPA and FERC Order No. 636. As discussed above, 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 materially adverse impact on the results of its operations, its financial position or its business prospects. Federal Energy Regulatory Commission SCE&G and GENCO are 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. 15 SCE&G holds licenses under the Federal Water Power Act or the Federal Power Act with respect to all its hydroelectric projects. The expiration dates of the licenses covering the projects are as follows: Project Capability (KW) License Expiration Date Neal Shoals 5,000 1993 Stevens Creek 9,000 1993 Columbia 10,000 2000 Saluda 206,000 2007 Parr Shoals 14,000 2020 Fairfield Pumped Storage 512,000 2020 Pursuant to the provisions of the Federal Power Act as amended by the Electric Consumers Protection Act of 1986, applications for new licenses for Neal Shoals and Stevens Creek were filed with the FERC on December 30, 1991. No competing applications were filed. The Neal Shoals license application was declared to be ready for environmental analysis by FERC Notice dated June 3, 1994, and the Stevens Creek Application was declared to be ready by FERC Notice dated September 6, 1994. FERC has issued Notices of Authorization for Continued Project Operation for both projects until FERC has acted on SCE&G's applications for new licenses. FERC is in the process of performing a Multiple-project Environmental Assessment for Neal Shoals, and a Single-project Environmental Assessment for Stevens Creek. At the termination of a license under the Federal Power Act, the United States government may take over the project covered thereby, or the FERC may extend the license or issue a license to another applicant. If the United States takes over a project or the FERC issues a license to another applicant, the original licensee shall be paid its net investment in the project, not to exceed fair value, plus severance damages. Nuclear Regulatory Commission SCE&G is subject to regulation by the NRC with respect to the ownership and operation of Summer Station. The NRC's jurisdiction encompasses broad supervisory and regulatory powers over the construction and operation of nuclear reactors, including matters of health and safety, antitrust considerations and environmental impact. The NRC conducts semiannual reviews that identify plants that have demonstrated an excellent level of safety performance. For the sixth consecutive time, the NRC named Summer Station to its short list of top performing plants. In addition, the Federal Emergency Management Agency is responsible for the review, in conjunction with the NRC, of certain aspects of emergency planning relating to the operation of nuclear plants. RATE MATTERS The following table presents a summary of significant rate activity for the years 1990 - 1994 based on test years: REQUESTED GRANTED Date of % of General Rate Application/ Amount % Increase Date of Amount Increase Applications Hearing (Millions) Requested Order (Millions) Granted PSC Electric Retail 12/07/92 $ 72.0* 11.4% 06/07/93 $ 60.5 84% Retail 01/03/89 $ 27.2 3.7% 07/03/89 $ 18.2** 67%** Transit Fares 03/12/92 $ 1.7 42.0% 09/14/92 $ 1.0 59%
*As modified to reflect lowering of rate of return SCE&G was seeking. **Reflects a rate reduction of $3.7 million on January 4, 1993 (see discussion below) and excludes impact of rate reduction of $7.7 million on January 3, 1990 which corresponds to $7.7 million reduction in cost-of-service resulting from NRC approval of extension of Summer Station's operating life to 40 years. 16 On October 27, 1994 the PSC issued an order approving SCE&G'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 SCE&G's gas operations that had previously been deferred. On June 7, 1993 the PSC issued an order on SCE&G's pending electric rate proceeding allowing an authorized return on common equity of 11.5%, resulting in a 7.4% annual increase in retail electric rates, or a projected $60.5 million annually, based on a test year. These rates are to be implemented in two phases over a two-year period: phase one, effective June 1993, producing $42.0 million annually, and phase two, effective June 1994, producing $18.5 million annually, based on a test year. On September 14, 1992 the PSC issued an order granting SCE&G 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 SCE&G's request to reduce the number of routes and frequency of service. The new rates were placed into effect on October 5, 1992. SCE&G has appealed the PSC's order to the Circuit Court. Effective with the first billing cycle in December 1991, SCE&G's gas rate schedules for its residential, small commercial and small industrial customers have included a weather normalization adjustment (WNA). The WNA minimizes fluctuations in gas revenues due to abnormal weather conditions and is subject to an annual review by the PSC. The PSC order was based on a return on common equity of 12.25%. On August 26, 1994, the PSC ordered that the WNA be made permanent. In May 1989 the PSC approved a volumetric and direct billing method for Pipeline Corporation to recover take-or-pay costs incurred from its interstate pipeline suppliers pursuant to FERC- approved final and non-appealable settlements. In December 1992 the Supreme Court approved Pipeline Corporation's full recovery of the take-or-pay charges imposed by its suppliers and treatment of these charges as a cost of gas. However, the Supreme Court declared the PSC-approved "purchase deficiency" methodology for recovery of these costs to be unlawful retroactive ratemaking and remanded the docket to the PSC to reconsider its recovery methodology. On April 30, 1994 the PSC issued an order regarding Pipeline Corporation's recovery of take-or-pay cost incurred pursuant to FERC-approved settlements with its upstream interstate pipeline suppliers. This order provided a mechanism for Pipeline Corporation to recover its take-or-pay cost volumetrically over a period of approximately 30 months. SCE&G receives a credit for payments made prior to the April 30 order which is netted against the current volumetric surcharge. That net cost is recovered by SCE&G through its purchased gas adjustment clause. On August 8, 1990 the PSC issued an order effective November 1, 1990, approving changes in Pipeline Corporation's gas rate design for sales for resale service and upholding the "value-of-service" method of regulation for its direct industrial service. Direct industrial customers seeking "cost-of-service" based rates initiated two separate appeals to the Circuit Court, which reversed and remanded to the PSC its August 8, 1990 order. Pipeline Corporation appealed that decision to the Supreme Court which on January 10, 1994 reversed the two Circuit Court decisions and reinstated the PSC Order. The Supreme Court held that the industrial customer group's appeal was premature and failed to exhaust administrative remedies. Additionally, the Supreme Court interpreted the rate-making statutes of South Carolina to give discretion to the PSC in selecting the methodology to be used in setting rates for natural gas service. On July 3, 1989 the PSC granted SCE&G approximately $21.9 million of a requested $27.2 million annual increase in retail electric revenues based upon an allowed return on common equity of 13.25%. The Consumer Advocate appealed the decision to the Supreme Court which, on August 31, 1992, found that the evidence in the record of that case did not support a return on common equity higher than 13.0% and remanded to the PSC a portion of its July 1989 order for a determination of the proper return on common equity consistent with the Supreme Court's opinion. On January 19, 1993 the PSC issued an order allowing a return on common equity of 13.0%, approving a refund based on the difference in rates created by the difference between the 13.0% and the 13.25% return on common equity and making other non-material adjustments to the calculation of cost-of-service. The total refund, before interest and income taxes, was approximately $14.6 million and was charged against 1992 "Electric Revenues." The refund plus interest was made during 1993. 17 Fuel Cost Recovery Procedures The PSC has established a fuel cost recovery procedure which determines the fuel component in SCE&G'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. SCE&G has the right to request a formal proceeding at any time should circumstances dictate such a review. In the April 1994 semiannual review of the fuel cost component of electric rates, the PSC voted to increase the rate from 13.0 mills per KWH to 14.16 mills per KWH, a monthly increase of $1.16 for an average customer using 1,000 KWH per month. For the October 1994 review the PSC voted to continue the rate of 14.16 mills per KWH. SCE&G's gas rate schedules and contracts include mechanisms which allow it to recover from its customers changes in the actual cost of gas. SCE&G's firm gas rates allow for the recovery of a fixed cost of gas, based on projections, as established by the PSC in annual gas cost and gas purchase practice hearings. Any differences between actual and projected gas costs are deferred and included when projecting gas costs during the next annual gas cost recovery hearing. In the October 1994 review the PSC authorized an increase in the base cost of gas from 47.100 cents per therm to 51.058 cents per therm which resulted in a monthly increase of $3.96 (including applicable taxes) based on an average of 100 therms per month on a residential bill during the heating season. ENVIRONMENTAL MATTERS General Federal and state authorities have imposed upon the Company environmental regulations and standards relating primarily to air emissions, wastewater discharges and solid, toxic and hazardous waste management. It is difficult to forecast the ultimate effect of these regulations and standards upon existing and proposed operations. Moreover, developments in these areas may require that equipment and facilities be modified, supplemented or replaced. Capital Expenditures In the years 1992 through 1994, capital expenditures for environmental control amounted to approximately $105.0 million. In addition, approximately $11.1 million, $9.4 million, and $7.9 million of environmental control expenditures were made during 1994, 1993 and 1992, respectively, which are included in "Other operation" and "Maintenance" expenses. It is not possible to estimate all future costs for environmental purposes but forecasts for minimum capitalized expenditures are $37.4 million for 1995 and $215.9 million for the four-year period 1996 through 1999. These expenditures are included in the Company's construction program. 18 Air Quality Control The Clean Air Act requires electric utilities to reduce substantially emissions of sulfur dioxide and nitrogen oxide by the year 2000. These requirements are being phased in over two periods. The first phase has a compliance date of January 1, 1995 and the second, January 1, 2000. The Company meets all requirements of Phase I and, therefore, will not have to implement changes until compliance with Phase II requirements is necessary. The Company then will most likely meet its compliance requirements through the burning of natural gas and/or lower sulfur coal, the addition of scrubbers to coal-fired generating units, and the purchase of sulfur dioxide emission allowances. At December 31, 1994, the Company had purchased $19.4 million in emission allowances and had commitments to purchase $6.8 million in emission allowances in 1995. Low nitrogen oxide burners will be installed to reduce nitrogen oxide emissions. The Company is continuing to refine a compliance plan that must be filed with the EPA by January 1, 1996. The Company currently estimates that air emissions control equipment will require capital expenditures of $158 million over the 1995-1999 period to retrofit existing facilities and an increased operation and maintenance cost of approximately $1 million per year. To meet compliance requirements through the year 2004, the Company anticipates total capital expenditures of $287 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 SCE&G'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 the additional parameters of control and compliance has involved updating wastewater treatment technologies. Amendments to the Clean Water Act proposed recently in Congress include several provisions which could prove costly to SCE&G. These include limitations to mixing zones and the implementation of technology-based standards. Superfund Act and Environmental Assessment Program As described in Note 1L of Notes to Consolidated Financial Statements, the Company has an environmental assessment program to identify and assess current and former operations sites that could require environmental cleanup. As site assessments are initiated, an estimate is made of the amount of expenditures, if any, necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations; such amounts have been deferred and are being amortized and recovered through rates over a ten-year period for electric operations and an eight-year period for gas operations. Such deferred amounts totaled $20.2 million and $19.6 million at December 31, 1994 and 1993, respectively. Estimates to date include, among other things, the costs estimated to be associated with the matters discussed in the following paragraphs. The Company's principal subsidiary, SCE&G, owns five decommissioned manufactured gas plant sites which contain residues of by-product chemicals. SCE&G has maintained an active review of the sites to monitor the nature and extent of the residual contamination. 19 In September 1992 the EPA notified SCE&G, the City of Charleston and the Charleston Housing Authority of their potential liability for the investigation and cleanup of the Calhoun Park Area Site in Charleston, South Carolina. This site originally encompassed approximately 18 acres and included properties which were the locations for industrial operations, including a wood preserving (creosote) plant and one of SCE&G's decommissioned manufactured gas plants. The original scope of this investigation has been expanded to approximately 30 acres, including adjacent properties owned by the National Park Service and the City of Charleston, and private properties. The site has not been placed on the National Priority List, but may be added before cleanup is initiated. The potentially responsible parties (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 (RI/FS) and a corresponding Scope of Work. Actual field work began November 1, 1993 after final approval and authorization was granted by EPA. SCE&G 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 SCE&G that it considers SCE&G 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. SCE&G 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. SCE&G has been listed as a PRP and has recorded liabilities, which are not considered material, for the Macon-Dockery waste disposal site near Rockingham, North Carolina, the Aqua-Tech Environmental Inc. site in Greer, South Carolina and a landfill owned by Lexington County in South Carolina. The Arkansas Department of Pollution Control and Ecology (ADPCE) has identified SCE&G as a PRP for clean-up of PCBs at an abandoned transformer rebuilding plant in Little Rock, Arkansas. No formal notice from ADPCE has been received concerning this issue. SCE&G does not believe that the resolution of this issue will have a material effect on SCE&G's results of operations or financial position. Solid Waste Control The South Carolina Solid Waste Policy and Management Act of 1991 requires promulgation of regulations addressing specified subjects, one of which affects the management of industrial solid waste. This regulation will establish minimum criteria for industrial landfills as mandated under the Act. The proposed regulation, if adopted as a final regulation in its present form, could significantly impact SCE&G's and GENCO's engineering, design and operation of existing and future ash management facilities. Potential cost impacts could be substantial. Nuclear Fuel Disposal The Nuclear Waste Policy Act of 1982 requires that the United States government make available by 1998 a permanent repository for high level radioactive waste and spent nuclear fuel and imposes a fee of 1.0 mill per KWH of net nuclear generation after April 7, 1983. Payments, which began in 1983, are subject to change and will extend through the operating life of SCE&G's Summer Station. SCE&G 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. SCE&G has on-site spent fuel storage capability until at least 2008 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. The Act also imposes on utilities the primary responsibility for storage of their spent nuclear fuel until the repository is available. 20 OTHER MATTERS With regard to SCE&G's insurance coverage for Summer Station, reference is made to Note 10B of Notes to Consolidated Financial Statements, which is incorporated herein by reference. The Company's net investment in oil and gas properties is subject to a quarterly ceiling limitation calculation that is based on the future net revenues from forecasted production of proved oil and gas reserves valued at current or contract prices. Carrying values of proved reserves in excess of the ceiling limitation are expensed currently. In an effort to limit exposure to changing natural gas prices and to avoid a writedown resulting from the application of the ceiling test at December 31, 1994, in January 1995 the Company entered into a series of forward contacts relating to natural gas production. These forward contracts have the effect of stabilizing the price that the Company will receive on approximately sixty percent of its forecasted natural gas production for the years 1995-2001. The forward contracts are at an average price of $1.88 per dekatherm. If market prices exceed the forward contracts' prices at the time of delivery, the Company will forego additional revenues to the extent of the price differential for the quantities subject to such forward contracts. However, the Company believes these forward contracts are appropriate in light of current market conditions and that the forward contracts reduce the Company's exposure to price risk. The Company remains exposed to price risk for any production that is not subject to such forward contracts. ITEM 2. PROPERTIES SCANA owns no property other than the capital stock of each of its subsidiaries. It owns all of the capital stock of each subsidiary except for the Preferred Stock of SCE&G and the capital stock of SCANA's indirect, wholly owned subsidiaries which are not material individually or in the aggregate. The assets formerly belonging to Peoples, acquired by SCANA Corporation in 1990, were transferred to SCE&G on January 1, 1994. SCE&G'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. GENCO's Williams Station is subject to a first mortgage lien. For a brief description of the properties of the Company's other subsidiaries, which are not significant as defined in Rule 1- 02 of Regulation S-X, see Item 1, "Business." 21 ELECTRIC The following table gives information with respect to electric generating facilities, all of which are owned by SCE&G except as noted. Net Generating Present Year Capability Facility Fuel Capability Location In-Service (KW)(1) Steam (2) Urquhart Coal/Gas Beech Island, SC 1953 250,000 McMeekin Coal/Gas Irmo, SC 1958 252,000 Canadys Coal/Gas Canadys, SC 1962 430,000 Wateree Coal Eastover, SC 1970 700,000 Williams (3) Coal Goose Creek, SC 1973 560,000 Summer (4) Nuclear Parr, SC 1984 590,000 Gas Turbines Burton Gas/Oil Burton, SC 1961 28,500 Faber Place Gas Charleston, SC 1961 9,500 Hardeeville Oil Hardeeville, SC 1968 14,000 Canadys Gas/Oil Canadys, SC 1968 14,000 Urquhart Gas/Oil Beech Island, SC 1969 38,000 Coit Gas/Oil Columbia, SC 1969 30,000 Parr (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 3,876,000 (1) Summer rating. (2) Excludes Cope Electric Generating Station, a 385,000 KW plant currently under construction and scheduled for commercial operation in early 1996. (3) The steam unit at Williams Station, owned by GENCO, was converted from oil-fired to coal-fired operation in 1984 and, with modifications, can be reconverted to oil-fired operation should the need arise. (4) Represents SCE&G's two-thirds portion of the Summer Station. (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. (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. 22 SCE&G owns 445 substations having an aggregate transformer capacity of 18,885,437 KVA. The transmission system consists of 3,057 miles of lines and the distribution system consists of 15,421 pole miles of lines and 3,122 trench miles of underground lines. GAS Natural Gas SCE&G's gas system, including the Peoples system acquired by SCANA and transferred to SCE&G on January 1, 1994, consists of approximately 6,719 miles of three-inch equivalent distribution pipelines and approximately 11,078 miles of distribution mains and related service facilities. Pipeline Corporation's gas system consists of approximately 1,759 miles of transmission pipeline of up to 24 inches in diameter which connect its resale customers' distribution systems with transmission systems of Southern Natural and Transco. Pipeline Corporation owns two LNG plants, one located near Charleston, South Carolina the other in Salley, South Carolina. The Charleston facility can liquefy up to 6,000 MCF per day and store the liquefied equivalent of 1,000,000 MCF of natural gas. The Salley facility, which became operational in 1994, can store the liquefied equivalent of 900,000 MCF of natural gas and has no liquefying capabilities. On peak days, the Charleston facility can regasify up to 60,000 MCF per day and the Salley facility can regasify up to 90,000 MCF. Petroleum Resources owns and/or operates oil and gas properties in Texas, Louisiana, Mississippi, Oklahoma, California, Arkansas, Nebraska, Kansas, New Mexico, Alabama, Wyoming and Utah and Federal waters offshore Texas, Louisiana and Alabama. Propane SCE&G 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 SCE&G owns 97 motor coaches which operate on a route system of 285 miles. ITEM 3. LEGAL PROCEEDINGS For information regarding legal proceedings, see ITEM 1., "BUSINESS" and Note 10 of Notes to Consolidated Financial Statements appearing in Item 8., "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA." ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS Not Applicable 23 CORPORATE STRUCTURE SCANA CORPORATION A Holding Company, Owning Twelve Direct, Wholly Owned Subsidiaries SOUTH CAROLINA SCANA HYDROCARBONS, INC. ELECTRIC & GAS COMPANY Markets natural gas as well Generates and sells electricity as other light hydrocarbons to wholesale and retail customers, and owns and operates a natural purchases, sells and transports gas gathering system in Oklahoma. natural gas at retail and provides Owns and operates a propane public transit service in Columbia pipeline and provides for and Charleston. transportation and bulk storage of propane. SOUTH CAROLINA GENERATING COMPANY, INC. SCANA PETROLEUM RESOURCES, INC. Owns and operates Williams Owns and/or operates oil and gas Station and sells electricity properties. to SCE&G. SERVICECARE, INC. SOUTH CAROLINA FUEL Provides energy related products COMPANY, INC. and services beyond the energy Acquires, owns and provides for meter, principally service financing for SCE&G's nuclear contracts on home appliances. fuel, fossil fuel and sulfur dioxide emission allowances. PRIMESOUTH, INC. Engages in power plant SUBURBAN PROPANE GROUP, INC. management and maintenance Purchases, delivers and services. sells propane. SCANA DEVELOPMENT CORPORATION SCANA CAPITAL RESOURCES, INC. Engaged in the acquisition, Has provided equity capital development, management and for diversified investments. sale of real estate. (In liquidation.) MPX SYSTEMS, INC. Provides fiber optic SOUTH CAROLINA PIPELINE telecommunications, video CORPORATION conferencing, specialized Purchases, sells and transports mobile radio services and is natural gas to wholesale and pursuing Personal Communication direct industrial customers. Services licenses for wireless Owns and operates two LNG plants communications. for the liquefaction, regasifi- cation and storage of natural gas. Each of the above listed companies is organized and incorporated under the laws of the State of South Carolina. 24 EXECUTIVE OFFICERS OF THE REGISTRANT The executive officers are elected at the annual organizational meeting of the Board of Directors, held immediately after the annual meeting of stockholders, 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. 63 Chairman of the Board, Chief Executive Officer and President *-present W.B. Timmerman 48 Executive Vice President 1994-present Assistant Secretary 1993-present Senior Vice President *-1994 Chief Financial Officer and Controller *-present B.D. Kenyon 52 President and Chief Operating Officer - SCE&G 1990-present Senior Vice President - Division Operations, Pennsylvania Power and Light Company *-1990 A. H. Gibbes 48 Senior Vice President - 1994-present SCANA and Assistant Secretary - SCE&G GENCO, Fuel Company, MPX, PrimeSouth, ServiceCare and SCANA Development Corp. General Counsel and Assistant Secretary 1993-present President and Treasurer - SCANA Development Corp. 1990-present C.B. Novinger 45 Senior Vice President - Administration *-present Max Earwood 62 President and Treasurer - South Carolina Pipeline Corporation *-present President and Treasurer - SCANA Hydrocarbons, Inc.; SCANA Petroleum Resources, Inc.; *-present Vice President - Gas Distribution, SCE&G *-1991 K.B. Marsh 39 Vice President - Finance, Treasurer & Secretary 1992-present Vice President of Corporate Planning - SCE&G 1991 Vice President and Controller - SCE&G 1989-1991 *Indicates position held at least since March 1, 1990 25 PART II ITEM 5. MARKET FOR REGISTRANT'S COMMON STOCK AND RELATED SECURITY HOLDER MATTERS COMMON STOCK INFORMATION 1994 1993 4th 3rd 2nd 1st 4th 3rd 2nd 1st Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Qtr. Price Range: (a) High 44 5/8 46 46 1/2 50 1/8 52 1/4 51 7/8 48 3/8 46 1/2 Low 41 42 3/4 42 1/8 44 3/4 47 7/8 47 5/8 45 40 1/8 Dividends Per Share: 1994 Amount Date Declared Date Paid First Quarter $.705 February 15,1994 April 1, 1994 Second Quarter .705 April 28, 1994 July 1, 1994 Third Quarter .705 August 24, 1994 October 1, 1994 Fourth Quarter .705 October 18, 1994 January 1, 1995 1993 Amount Date Declared Date Paid First Quarter $.685 February 16, 1993 April 1, 1993 Second Quarter .685 April 29, 1993 July 1, 1993 Third Quarter .685 August 25, 1993 October 1, 1993 Fourth Quarter .685 October 19, 1993 January 1, 1994 December 31, 1994 1993 Number of common shares outstanding 48,017,510 46,619,457 Number of common stockholders of record 39,516 41,564 The principal market for SCANA common stock is the New York Stock Exchange. The ticker symbol used is SCG. The corporate name SCANA is used in newspaper stock listings. The total number of shares of SCANA common stock outstanding at February 28, 1995 was 48,330,982. (a) As reported on the New York Stock Exchange Composite Listing. SECURITIES RATINGS (As of December 31, 1994) SCANA CORPORATION SOUTH CAROLINA ELECTRIC & GAS COMPANY Rating First Mortgage First and Refunding Preferred Commercial Agency Medium-Term Notes Bonds Mortgage Bonds Stock Paper Duff & Phelps NR A+ A+ A NR Moody's A3 A1 A1 a1 P-1 Standard & Poor's A- A A A- A-1 NR - Not Rated Further reference is made to Note 5 of Notes to Consolidated Financial Statements. 26 ITEM 6. SELECTED FINANCIAL DATA SELECTED FINANCIAL DATA For the Years Ended December 31, 1994 1993 1992 1991 1990 1984 Statement of Income Data (Thousands of dollars except statistics and per share amounts) Operating Revenues: Electric $ 975,388 $ 940,121 $ 829,477 $ 867,215 $ 851,146 $ 755,502 Gas 342,672 320,195 305,275 276,742 292,380 378,491 Transit 4,002 3,851 3,623 3,869 4,033 3,178 Total Operating Revenues 1,322,062 1,264,167 1,138,375 1,147,826 1,147,559 1,137,171 Operating Expenses: Fuel used in electric generation and purchased power 255,240 242,793 213,474 234,683 223,972 235,246 Gas purchased for resale 220,923 208,695 191,577 171,869 191,939 289,212 Other operation and maintenance 293,721 290,891 281,242 270,213 265,887 184,727 Depreciation and amortization 119,177 112,844 108,315 102,669 97,801 74,914 Taxes 173,448 163,633 133,987 146,032 142,003 153,776 Total Operating Expenses 1,062,509 1,018,856 928,595 925,466 921,602 937,875 Operating Income 259,553 245,311 209,780 222,360 225,957 199,296 Other Income 5,998 30,076 11,883 11,655 54,874 17,647 Income Before Interest Charges and Preferred Stock Dividends 265,551 275,387 221,663 234,015 280,831 216,943 Interest Charges, Net 108,397 101,189 97,600 91,458 92,317 78,248 Preferred Stock Cash Dividends of Subsidiary 5,955 6,217 6,473 6,706 6,911 16,877 Net Income $ 151,199 $ 167,981 $ 117,590 $ 135,851 $ 181,603 $ 121,818 Percent of Operating Income (Loss) Before Income Taxes Electric 88% 90% 85% 89% 89% 87% Gas 14% 13% 18% 14% 14% 15% Transit (2%) (3%) (3%) (3%) (3%) (2%) Common Stock Data Weighted Average Number of Common Shares Outstanding (Thousands) 47,381 45,203 41,475 40,361 40,882 39,900 Earnings Per Weighted Average Share of Common Stock $3.19 $3.72 $2.84 $3.37 $4.44 $3.05 Dividends Declared Per Share of Common Stock $2.82 $2.74 $2.68 $2.62 $2.52 $2.05 Common Shares Outstanding (Year-End) (Thousands) 48,018 46,619 43,911 40,784 40,882 40,296 Book Value Per Share of Common Stock (Year-End) $29.37 $28.59 $26.46 $25.23 $24.56 $19.31 27 December 31, 1994 1993 1992 1991 1990 1984 Balance Sheet Data (Thousands of dollars except statistics and per share amounts) Utility Plant, Net $3,293,667 $3,004,075 $2,810,279 $2,664,651 $2,549,763 $2,205,297 Total Assets $4,393,128 $4,040,526 $3,557,721 $3,305,862 $3,144,936 $2,506,996 Common Equity $1,410,438 $1,333,045 $1,161,896 $1,028,990 $1,003,877 $ 778,251 Preferred Stock (Not subject to purchase or sinking fund requirements) 26,027 26,027 26,027 26,027 26,027 26,262 Preferred Stock, Net (Subject to purchase or sinking fund requirements) 49,528 52,840 56,154 59,469 62,704 152,974 Long-Term Debt, Net 1,537,624 1,424,399 1,204,754 1,122,396 938,933 900,878 Total Capitalization $3,023,617 $2,836,311 $2,448,831 $2,236,882 $2,031,541 $1,858,365 Other Statistics Electric: Customers (Year-End) 476,412 468,874 461,900 453,660 446,516 378,963 Territorial sales (Million KWH) 16,838 16,880 15,794 15,695 15,385 12,590 Residential: Average annual use per customer (KWH) 13,048 14,077 13,037 13,246 13,330 12,061 Average annual rate per KWH $.0743 $.0707 $.0695 $.0700 $.0707 $.0757 Generating Capability - Net MW (Year-End) 3,876 3,864 3,912 3,912 3,891 3,959 Territorial Peak Demand - Net MW 3,444 3,557 3,380 3,300 3,222 2,596 Gas: Customers (Year-End) 238,614 234,736 231,153 225,819 220,817 189,544 Sales (Thousand Therms) 781,109 717,417 761,721 694,801 711,821 737,059 Residential: Average annual use per customer (therms) 543 605 577 521 497 618 Average annual rate per therm $.84 $.76 $.74 $.77 $.77 $.69 28 ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS COMPETITION The electric utility industry has begun a major transition that could lead to expanded market competition and less regulatory protection. The transition began with the enactment of the Public Utility Regulatory Policies Act of 1978 which facilitated the entry of competitors into the electric generation business. Subsequently, the National Energy Policy Act (NEPA) was enacted in 1992 to promote competition among utility and nonutility generators in the wholesale electric generation market. Recent initiatives in some states to lessen regulation and promote competition, particularly with regard to retail transmission access, also have accelerated the utility industry's transition. Future deregulation of electric wholesale and retail markets will create opportunities to compete for new and existing customers and markets. As a result, profit margins and asset values of some utilities could be adversely affected. The pace of deregulation, the future market price of electricity, and the regulatory actions which may be taken by the Public Service Commission of South Carolina (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's electric and gas utility, SCE&G, reorganized its operations around Strategic Business Units. Maintaining a competitive cost structure is of paramount importance in the utility's strategic plan. SCE&G has undertaken a variety of initiatives, including reductions in operations and maintenance costs and in staffing levels. SCE&G believes that these actions as well as numerous others that have been and will be taken demonstrate its ability and commitment to succeed in the new operating environment to come. LIQUIDITY AND CAPITAL RESOURCES The cash requirements of the Company arise primarily from SCE&G's operational needs, the Company's construction program and the need to fund the activities or investments of the Company's nonregulated subsidiaries. The ability of the Company's regulated subsidiaries to replace existing plant investment, as well as to expand to meet future demand for electricity and gas, will depend upon their ability to attract the necessary financial capital on reasonable terms. The Company's regulated subsidiaries recover 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 regulated subsidiaries expand their construction programs, 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 the regulated subsidiaries' ability to obtain adequate and timely rate relief. Due to continuing customer growth, SCE&G entered into a contract with Duke/Fluor Daniel in 1991 to design, engineer and build a 385 MW coal-fired electric generating plant near Cope, South Carolina in Orangeburg County. Construction of the plant began in November 1992 and is expected to be complete in late 1995 with commercial operation beginning in early 1996. The estimated cost of the Cope plant, excluding financing costs and allowance for funds used during construction (AFC), but including an allowance for escalation, is $450 million. In addition, the transmission lines for interconnection with the Company's system are expected to cost $26 million. Until the completion of the new plant, SCE&G is contracting for additional capacity as necessary to ensure that the energy demands of its customers can be met. As discussed in Note 2B of Notes to Consolidated Financial Statements, on June 7, 1993 the PSC issued an order granting SCE&G a 7.4% annual increase in retail electric rates which was implemented in two phases over a two year period: phase one, effective June 1993, producing $42.0 million annually, and phase two, effective June 1994, producing $18.5 million annually, based on a test year. 29 The estimated primary cash requirements for 1995, excluding requirements for fuel liabilities and short-term borrowings, and the actual primary cash requirements for 1994 are as follows: 1995 1994 (Thousands of Dollars) Property additions and construction expenditures, excluding allowance for funds used during construction (AFC) $348,530 $471,175 Acquisition of oil and gas producing properties - 47,189 Nuclear fuel expenditures 23,084 27,429 Maturing obligations, redemptions and sinking and purchase fund requirements 25,630 30,373 Total $397,244 $576,166 Approximately 31% of total cash requirements (excluding dividends) was provided from internal sources in 1994 as compared to 28% in 1993. The Company has in effect a medium-term note program for the issuance from time to time of unsecured medium-term debt securities. The proceeds from the sales of these securities may be used to fund additional business activities in nonutility subsidi- aries, to reduce short-term debt incurred in connection therewith or for general corporate purposes. In December 1994, a shelf registration statement filed with the Securities and Exchange Commission became effective providing for the issuance of up to an additional $250 million in medium-term notes. At December 31, 1994 the Company had available for issuance $317.6 million. SCE&G's First and Refunding Mortgage Bond Indenture, dated April 1, 1945 (Old Mortgage), contains provisions prohibiting the issuance of additional bonds thereunder (Class A Bonds) unless net earnings (as therein defined) for 12 consecutive months out of the 15 months prior to the month of issuance are at least twice the annual interest requirements on all Class A Bonds to be outstanding (Bond Ratio). For the year ended December 31, 1994 the Bond Ratio was 3.52. The issuance of additional Class A Bonds is restricted also to an additional principal amount equal to 60% of unfunded net property additions (which unfunded net property additions totaled approximately $499.8 million at December 31, 1994), Class A Bonds issued on the basis of retirements of Class A Bonds (no earned retirement credits remaining at December 31, 1994), and Class A Bonds issued on the basis of cash on deposit with the Trustee. SCE&G has placed a new bond indenture (New Mortgage) dated April 1, 1993 on substantially all of its electric properties under which its future mortgage-backed debt (New Bonds) will be issued. New Bonds are expected to be issued under the New Mortgage on the basis of a like principal amount of Class A Bonds issued under the Old Mortgage which have been deposited with the Trustee of the New Mortgage (of which $57 million were available for such purpose as of December 31, 1994), until such time as all presently outstanding Class A Bonds are retired. Thereafter, New Bonds will be issuable on the basis of property additions in a principal amount equal to 70% of the original cost of electric and common plant properties (compared to 60% of value for Class A Bonds under the Old Mortgage), cash deposited with the Trustee, and retirement of New Bonds. New Bonds will be issuable under the New Mortgage only if adjusted net earnings (as therein defined) for 12 consecutive months out of the 18 months immediately preceding the month of issuance are at least twice the annual interest requirements on all outstanding bonds (including Class A Bonds) and New Bonds to be outstanding (New Bond Ratio). For the year ended December 31, 1994 the New Bond Ratio was 4.85. 30 The following additional financing transactions have occurred since December 31, 1993: , On January 14, 1994 the Company closed unsecured bank loans totaling $60 million due January 13, 1995, and used the proceeds to pay off a loan in a like total amount. In January 1995 the Company refinanced the loans with an unsecured bank loan of $60 million due January 12, 1996 at an initial interest rate of 6.44%, subject to reset quarterly at LIBOR plus ten basis points. , On July 21, 1994 SCE&G issued $100 million of First Mortgage Bonds, 7.70% series due July 15, 2004 to repay short-term borrowings in a like amount. , On November 3, 1994 SCE&G issued $30 million of Pollution Control Facilities Revenue Bonds due November 1, 2024. The proceeds from the sale of the bonds are being used to defray the cost of constructing certain facilities for the disposal of solid waste at SCE&G's Cope Generating Station under construction in Orangeburg County, South Carolina. Without the consent of at least a majority of the total voting power of SCE&G's preferred stock, SCE&G 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 SCE&G'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, SCE&G and GENCO must obtain FERC authority to issue short-term indebtedness. The FERC has authorized SCE&G to issue up to $200 million of unsecured promissory notes or commercial paper with maturity dates of 12 months or less, but not later than December 31, 1997. GENCO has not sought such authorization. The Company had $479.1 million authorized lines of credit and had unused lines of credit of $455.1 million at December 31, 1994. In addition, SCE&G has a credit agreement for a maximum of $75 million to finance nuclear and fossil fuel inventories, with $24.4 million available at December 31, 1994. SCE&G's Restated Articles of Incorporation prohibit issuance of additional shares of preferred stock without consent of the preferred stockholders unless net earnings (as defined therein) for the 12 consecutive months immediately preceding the month of issuance are at least one and one-half times the aggregate of all interest charges and preferred stock dividend requirements (Preferred Stock Ratio). For the year ended December 31, 1994 the Preferred Stock Ratio was 2.29. On December 16, 1994 the Company registered with the SEC 2,000,000 additional shares of the Company's common stock to be issued and sold under the SPSP. During 1994 the Company issued 595,438 shares of the Company's common stock under the DRP. In addition, the Company issued 781,354 shares of its common stock pursuant to its SPSP. The Company has authorized and reserved for issuance, and registered under effective registration statements, 1,470,386 and 2,091,066 shares of common stock pursuant to the DRP and the SPSP, respectively. 31 In January 1994 the Company signed an agreement to sell substantially all of the real estate assets of SCANA Development Corporation to Liberty Properties Group, Inc. of Greenville, South Carolina for $91.5 million. On March 4, 1994 the Company and Liberty amended the agreement to exclude certain projects then under construction, and the sales price was reduced to $49.6 million. The transaction was closed on May 27, 1994. Certain other assets of SCANA Development Corporation are being sold to other parties. These transactions did not have a material impact on the Company's financial position or results of operations. MPX Systems Inc., a wholly owned subsidiary of SCANA, through a joint venture with ITC Transmission Systems, a Georgia-based telecommunications holding company, is constructing a fiber optic network through Texas, Louisiana, Mississippi, Alabama and Georgia. The network, which will consist of more than 900 miles of fiber optic lines, is expected to be completed by June 1995 at a cost of $58 million. In addition, MPX is pursuing Personal Communication Services licenses for wireless communications in the Southeast through a joint venture with ITC Personal Communications, Inc., Intercel PCS Services, Inc., and South Atlantic PCS Corporation. A $40 million construction loan obtained by the joint venture has been guaranteed in part by SCANA Corporation. All new ventures currently capitalize on the fiber infrastructure in place and provide for expansion of the network. The Company anticipates that its 1995 cash requirements of $397.2 million will be met through internally generated funds (approximately 42% excluding dividends), the sales of additional equity securities and the incurrence of additional short-term and long-term indebtedness. The timing and amount of such financing will depend upon market conditions and other factors. Actual 1995 expenditures may vary from the estimates set forth above due to factors such as inflation and economic conditions, regulation and legislation, rates of load growth, environmental protection standards and the cost and availability of capital. The Company expects that it has or can obtain adequate sources of financing to meet its projected cash requirements. Environmental Matters The Clean Air Act requires electric utilities to reduce substantially emissions of sulfur dioxide and nitrogen oxide by the year 2000. These requirements are being phased in over two periods. The first phase has a compliance date of January 1, 1995 and the second, January 1, 2000. The Company meets all requirements of Phase I and, therefore, will not have to implement changes until compliance with Phase II requirements is necessary. The Company then will most likely meet its compliance requirements through the burning of natural gas and/or lower sulfur coal, the addition of scrubbers to coal-fired generating units, and the purchase of sulfur dioxide emission allowances. At December 31, 1994, the Company had purchased $19.4 million in emission allowances and had commitments to purchase $6.8 million in emission allowances in 1995. Low nitrogen oxide burners will be installed to reduce nitrogen oxide emissions. The Company is continuing to refine a compliance plan that must be filed with the U.S. Environmental Protection Agency (EPA) by January 1, 1996. The Company currently estimates that air emissions control equipment will require capital expenditures of $158 million over the 1995-1999 period to retrofit existing facilities and an increased operation and maintenance cost of approximately $1 million per year. To meet compliance requirements through the year 2004, the Company anticipates total capital expenditures of $287 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 to meet the additional parameters of control, and compliance has involved updating wastewater treatment technologies. Amendments to the Clean Water Act proposed recently in Congress include several provisions which could prove costly to SCE&G. These include limitations to mixing zones and the implementation of technology-based standards. 32 The South Carolina Solid Waste Policy and Management Act of 1991 requires promulgation of regulations addressing specified subjects, one of which affects the management of industrial solid waste. This regulation will establish minimum criteria for industrial landfills as mandated under the Act. The proposed regulation, if adopted as a final regulation in its present form, could significantly impact SCE&G's and GENCO's engineering, design and operation of existing and future ash management facilities. Potential cost impacts could be substantial. As described in Note 1L of Notes to Consolidated Financial Statements, the Company has an environmental assessment program to identify and assess current and former operations sites that could require environmental cleanup. As site assessments are initiated, an estimate is made of the amount of expenditures, if any, necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations; such amounts have been deferred and are being amortized and recovered through rates over a ten-year period for electric operations and a eight-year period for gas operations. Such deferred amounts totaled $20.2 million and $19.6 million at December 31, 1994 and 1993, respectively. Estimates to date include, among other things, the costs associated with the matters discussed in the following paragraphs. SCE&G, the Company's principal subsidiary, owns five decommissioned manufactured gas plant sites which contain residues of by-product chemicals. SCE&G has maintained an active review of the sites to monitor the nature and extent of the residual contamination. In September 1992 the EPA notified SCE&G, the City of Charleston and the Charleston Housing Authority of their potential liability for the investigation and cleanup of the Calhoun Park Area Site in Charleston, South Carolina. This site originally encompassed approximately 18 acres and included properties which were the locations for industrial operations, including a wood preserving (creosote) plant and one of SCE&G's decommissioned manufactured gas plants. The original scope of this investigation has been expanded to approximately 30 acres, including adjacent properties owned by the National Park Service and the City of Charleston, and private properties. The site has not been placed on the National Priority List, but may be added before cleanup is initiated. The potentially responsible parties (PRP) have agreed with the EPA to participate in an innovative approach to site investigation and cleanup called "Superfund Accelerated Cleanup Model," allowing the pre-cleanup site investigations process to be compressed significantly. The PRPs have negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study (RI/FS) and a corresponding Scope of Work. Actual field work began November 1, 1993 after final approval and authorization was granted by the EPA. SCE&G 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 SCE&G that it considers SCE&G 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. SCE&G 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. SCE&G has been listed as a PRP and has recorded liabilities, which are not considered material, for the Macon-Dockery waste disposal site near Rockingham, North Carolina, the Aqua-Tech Environmental, Inc. site in Greer, South Carolina and a landfill owned by Lexington County in South Carolina. The Arkansas Department of Pollution Control And Ecology (ADPCE) has identified SCE&G as a PRP for clean-up of PCBs at an abandoned transformer rebuilding plant in Little Rock, Arkansas. No formal notice from ADPCE has been received concerning this issue. SCE&G does not believe that the resolution of this issue will have a material effect on SCE&G's results of operations or financial position. 33 Regulatory Matters On June 7, 1993 the PSC issued an order on SCE&G's pending electric rate proceeding allowing an authorized return on common equity of 11.5%, resulting in a 7.4% annual increase in retail electric rates, or a projected $60.5 million annually, based on a test year. These rates were implemented in two phases over a two- year period: phase one, effective June 1993, producing $42.0 million annually, and phase two, effective June 1994, producing $18.5 million annually, based on a test year. SCE&G anticipates filing for electric rate relief in 1995. The filing is anticipated to encompass primarily the remaining cost of completing the construction of the Cope Generating Station. The Company's regulated business operations are likely to be impacted by the NEPA and FERC Order No. 636. NEPA is designed to create a more competitive wholesale power supply market by creating "exempt wholesale generators" and by potentially requiring utilities owning transmission facilities to provide transmission access to wholesalers. Order No. 636 is intended to deregulate the markets for interstate sales of natural gas by requiring that pipelines provide transportation services that are equal in quality for all gas suppliers whether the customer purchases gas from the pipeline or another supplier. In the opinion of the Company, it will be able to meet successfully the challenges of these altered business climates and does not anticipate there to be any materially adverse impact on the results of its operations, its financial position or its business prospects. Other The Company's net investment in oil and gas properties is subject to a quarterly ceiling limitation calculation that is based on the future net revenues from forecasted production of proved oil and gas reserves valued at current or contract prices. Carrying values of proved reserves in excess of the ceiling limitation are expensed currently. In an effort to limit exposure to changing natural gas prices and to avoid a writedown resulting from the application of the ceiling test at December 31, 1994, in January 1995 the Company entered into a series of forward contacts relating to natural gas production. These forward contracts have the effect of stabilizing the price that the Company will receive on approximately sixty percent of its forecasted natural gas production for the years 1995-2001. The forward contracts are at an average price of $1.88 per dekatherm. If market prices exceed the forward contracts' prices at the time of delivery, the Company will forego additional revenues to the extent of the price differential for the quantities subject to such forward contracts. However, the Company believes these forward contracts are appropriate in light of current market conditions and that the forward contracts reduce the Company's exposure to price risk. The Company remains exposed to price risk for any production that is not subject to such forward contracts. 34 RESULTS OF OPERATIONS Earnings and Dividends Earnings per share of common stock, the percent increase (decrease) from the previous year and the rate of return earned on common equity for the years 1992 through 1994 were as follows: 1994 1993 1992 Earnings per weighted average share $3.19 $3.72 $2.84 Percent increase (decrease) in earnings per share (14.2%) 31.0% (15.7%) Return earned on common equity (year-end) 10.7% 12.6% 10.1% , 1994 Earnings per share and return on common equity decreased in 1994 primarily due to operations at Petroleum Resources, the Company's oil and natural gas exploration and production subsidiary. Petroleum Resources reported a net loss of $19.2 million for 1994, including an after-tax charge of $12.4 million recorded during the third quarter of 1994 to reflect an adjustment to accumulated depreciation, depletion and amortization and a writedown of the carrying value of certain of Petroleum Resources' gas properties based on a recently completed reserve study. , 1993 Earnings per share and return on common equity increased in 1993 primarily due to a higher electric sales margin and additional nonoperating income. The Company's financial statements include AFC. AFC is a utility accounting practice whereby a portion of the cost of both equity and borrowed funds used to finance construction (which is shown on the balance sheet as construction work in progress) is capitalized. An equity portion of AFC is included in nonoperating income and a debt portion of AFC is included in interest charges (credits) as noncash items both of which have the effect of increasing reported net income. AFC represented approximately 6.4% of income before income taxes in 1994, 5.7% in 1993 and 5.3% in 1992. In 1994 SCANA's Board of Directors raised the quarterly cash dividend on common stock to 70.5 cents per share from 68.5 cents per share. The increase, effective with the dividend payable on April 1, 1994, raised the indicated annual dividend rate to $2.82 per share from $2.74. SCANA has increased the dividend rate on its common stock in 41 of the last 42 years. Electric Operations , 1994 The increase in the electric sales margin from 1993 to 1994 is primarily the result of an increase in retail electric rates phased in over a two-year period beginning June 1993 and an increase in industrial sales, which more than offset the negative impact of a six percent decrease in residential sales of electricity due to milder weather in 1994. , 1993 The increase in electric sales margin from 1992 to 1993 is primarily a result of increased residential and commercial KWH sales due to weather and customer growth, an increase in retail electric rates beginning in June 1993 and the recording in 1992 of a $14.6 million reserve against earnings related to the August 31, 1992 retail electric rate ruling from the Supreme Court (see Note 2G of Notes to Consolidated Financial Statements). An increase of 7,538 electric customers to 476,412 total customers contributed to a 1994 peak demand of 3,444 MW on January 19. The all time peak demand record of 3,557 MW was set on July 29, 1993. 35 Gas Operations , 1994 The 1994 gas sales margin increased from 1993 primarily as a result of lower gas costs which allowed Pipeline Corporation to compete successfully with alternate fuel suppliers in industrial markets. Higher oil prices and a stronger economy had a positive impact on industrial sales which increased for both SCE&G and Pipeline Corporation. , 1993 In 1993 the gas sales margin decreased from 1992 as a result of higher gas prices which reducedPipeline Corporation's sales due to the competitiveness of alternate fuels. This reduction was partially offset by increases in higher margin residential and commercial sales and increased transportation volumes. Other Operating Expenses , 1994 Other operation and maintenance expenses increased for 1994 primarily due to an increase in the costs of postretirement benefits other than pensions which are accrued in accordance with Financial Accounting Standards Board Statement No. 106 (See Note 1J of Notes to Consolidated Financial Statements.) The increase in depreciation and amortization expenses is attributable to property additions and to increases in depreciation rates. The increase in other taxes reflects an increase in SCE&G's property taxes of approximately $5 million. , 1993 Other operation and maintenance expenses increased for 1993 primarily due to the implementation of Financial Accounting Standards Board Statement No. 106 (see Note 1J of Notes to Consolidated Financial Statements) pursuant to the June 1993 PSC electric rate order and the amortization of environmental expenses. The depreciation and amortization increase reflects additions to plant in service. The increase in income taxes corresponds to the increase in income and reflects the increase in the corporate tax rate from 34% to 35% retroactive to January 1, 1993. Other Income Other income, net of taxes, decreased approximately $23.3 million in 1994 primarily due to operations at Petroleum Resources. Petroleum Resources reported a net loss of $19.2 million for 1994 including an after-tax charge of $12.4 million recorded during the third quarter of 1994 to reflect an adjustment to accumulated depreciation, depletion, and amortization and a writedown of the carrying value of certain Petroleum Resources gas properties based on recently completed reserve study. In 1993 Petroleum Resources reported net income of $11.1 million. The Company's net investment in oil and gas properties is subject to a quarterly ceiling limitation calculation that is based on the future net revenues from forecasted production of proved oil and gas reserves valued at current or contract prices. Carrying values of proved reserves in excess of the ceiling limitation are expensed currently. In an effort to limit exposure to changing natural gas prices and to avoid a writedown resulting from the application of the ceiling test at December 31, 1994, in January 1995 the Company entered into a series of forward contacts relating to natural gas production. These forward contracts have the effect of stabilizing the price that the Company will receive on approximately sixty percent of its forecasted natural gas production for the years 1995-2001. The forward contracts are at an average price of $1.88 per dekatherm. If market prices exceed the forward contracts' prices at the time of delivery, the Company will forego additional revenues to the extent of the price differential for the quantities subject to such forward contracts. However, the Company believes these forward contracts are reasonable in light of current market conditions and that the forward contracts reduce the Company's exposure to price risk. The Company remains exposed to price risk for any production that is not subject to such forward contracts. 36 Interest Expense , 1994 The increase in interest expense (excluding the debt component of (AFC) is primarily attributable to the issuance of $100 million of First Mortgage Bonds in July and $30 million of Pollution Control Facilities Revenue Bonds in November, both to finance utility construction, and to the issuance of long-term debt during 1993. , 1993 Interest on long-term debt increased approximately $5.6 million in 1993 compared to 1992 due to the issuance of $72.4 million medium- term notes during the latter part of 1992 and $60 million medium-term notes in July 1993 to finance acquisitions of natural gas reserves and the issuance of $200 million of SCE&G's First Mortgage Bonds to finance utility construction. The resulting increases more than offset the interest savings resulting from the redemption and refinancing of $382 million of First and Refunding Mortgage Bonds with the proceeds from the issuance of $400 million of First Mortgage Bonds by SCE&G at lower interest rates. 37 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA TABLE OF CONTENTS OF CONSOLIDATED FINANCIAL STATEMENTS AND SUPPLEMENTARY FINANCIAL DATA Page Independent Auditor's Report....................................... 39 Consolidated Financial Statements: Consolidated Balance Sheets as of December 31, 1994 and 1993... 40 Consolidated Statements of Income and Retained Earnings for the years ended December 31, 1994, 1993 and 1992............. 42 Consolidated Statements of Cash Flows for the years ended December 31, 1994, 1993 and 1992............................. 43 Consolidated Statements of Capitalization as of December 31, 1994 and 1993................................... 44 Notes to Consolidated Financial Statements..................... 46 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. 38 INDEPENDENT AUDITORS' REPORT SCANA CORPORATION: We have audited the accompanying Consolidated Balance Sheets and Consolidated Statements of Capitalization of SCANA Corporation and subsidiaries (Company) as of December 31, 1994 and 1993 and the related Consolidated Statements of Income and Retained Earnings and of Cash Flows for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 1994 and 1993, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 1994 in conformity with generally accepted accounting principles. s/Deloitte & Touche LLP DELOITTE & TOUCHE LLP Columbia, South Carolina February 6, 1995 39
CONSOLIDATED BALANCE SHEETS December 31, 1994 1993 ASSETS (Thousands of Dollars) Utility Plant (Notes 1, 3 and 4): Electric $3,424,951 $3,328,915 Gas 467,576 451,493 Transit 3,785 3,769 Common 77,327 72,804 Total 3,973,639 3,856,981 Less accumulated depreciation and amortization 1,333,360 1,259,689 Total 2,640,279 2,597,292 Construction work in progress 582,628 349,530 Nuclear fuel, net of accumulated amortization 43,591 29,087 Acquisition adjustment-gas, net of accumulated amortization 27,169 28,166 Utility Plant, Net 3,293,667 3,004,075 Nonutility Property and Investments (Net of accumulated depreciation and depletion)(Note 1) 395,929 393,728 Current Assets: Cash and temporary cash investments (Note 8) 10,934 20,766 Receivables 183,180 174,121 Inventories (at average cost): Fuel (Notes 3 and 4) 60,273 62,977 Materials and supplies 47,463 46,890 Prepayments 19,853 21,826 Accumulated deferred income taxes 18,629 8,607 Total Current Assets 340,332 335,187 Deferred Debits: Emission allowances 19,409 - Unamortized debt expense 13,488 13,076 Unamortized deferred return on plant investment (Note 1) 10,614 14,860 Nuclear plant decommissioning fund (Note 1) 30,383 25,103 Other (Notes 1 and 10) 289,306 254,497 Total Deferred Debits 363,200 307,536 Total $4,393,128 $4,040,526 40 December 31, 1994 1993 CAPITALIZATION AND LIABILITIES (Thousands of Dollars) Stockholders' Investment (Note 5): Common equity $1,410,438 $1,333,045 Preferred stock (Not subject to purchase or sinking funds) 26,027 26,027 Total Stockholders' Investment 1,436,465 1,359,072 Preferred Stock, Net (Subject to purchase or sinking funds)(Notes 6 and 8) 49,528 52,840 Long-Term Debt, Net (Notes 3, 4 and 8) 1,537,624 1,424,399 Total Capitalization 3,023,617 2,836,311 Current Liabilities: Short-term borrowings (Notes 8 and 9) 183,027 43,019 Current portion of long-term debt (Note 3) 38,055 34,322 Current portion of preferred stock (Note 6) 2,418 2,504 Accounts payable 117,959 129,495 Estimated rate refunds and related interest (Note 2) - 2,509 Customer deposits 13,768 13,498 Taxes accrued 46,670 50,063 Interest accrued 25,226 21,784 Dividends declared 35,530 33,637 Other 17,220 12,649 Total Current Liabilities 479,873 343,480 Deferred Credits: Accumulated deferred income taxes (Notes 1 and 7) 589,026 568,172 Accumulated deferred investment tax credits (Notes 1 and 7) 91,349 94,981 Accumulated reserve for nuclear plant decommissioning (Note 1) 30,383 25,103 Other (Note 1) 178,880 172,479 Total Deferred Credits 889,638 860,735 Commitments and Contingencies (Note 10) - - Total $4,393,128 $4,040,526 See Notes to Consolidated Financial Statements. 41 CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS For the Years Ended December 31, 1994 1993 1992 (Thousands of Dollars except per share amounts) Operating Revenues (Notes 1 and 2): Electric $ 975,388 $ 940,121 $ 829,477 Gas 342,672 320,195 305,275 Transit 4,002 3,851 3,623 Total Operating Revenues 1,322,062 1,264,167 1,138,375 Operating Expenses: Fuel used in electric generation 235,136 229,736 206,151 Purchased power 20,104 13,057 7,323 Gas purchased for resale 220,923 208,695 191,577 Other operation (Note 1) 229,996 223,239 215,800 Maintenance (Note 1) 63,725 67,652 65,442 Depreciation and amortization (Note 1) 119,177 112,844 108,315 Income taxes (Notes 1 and 7) 94,510 90,007 60,947 Other taxes 78,938 73,626 73,040 Total Operating Expenses 1,062,509 1,018,856 928,595 Operating Income 259,553 245,311 209,780 Other Income (Note 1): Other income (loss), net of income taxes (2,178) 21,147 6,388 Allowance for equity funds used during construction 8,176 8,929 5,495 Total Other Income 5,998 30,076 11,883 Income Before Interest Charges and Preferred Stock Dividends 265,551 275,387 221,663 Interest Charges (Credits): Interest on long-term debt, net 108,804 98,695 93,052 Other interest expense 6,749 8,672 8,819 Allowance for borrowed funds used during construction (Note 1) (7,156) (6,178) (4,271) Total Interest Charges, Net 108,397 101,189 97,600 Income Before Preferred Stock Cash Dividends of Subsidiary 157,154 174,198 124,063 Preferred Stock Cash Dividends of Subsidiary (At stated rates) (5,955) (6,217) (6,473) Net Income 151,199 167,981 117,590 Retained Earnings at Beginning of Year 506,380 462,893 457,393 Common Stock Cash Dividends Declared (Note 5) (133,911) (124,494) (112,090) Retained Earnings at End of Year $ 523,668 $ 506,380 $ 462,893 Net Income $ 151,199 $ 167,981 $ 117,590 Weighted Average Number of Common Shares Outstanding (Thousands) 47,381 45,203 41,475 Earnings Per Weighted Average Share of Common Stock $3.19 $3.72 $2.84 See Notes to Consolidated Financial Statements. 42 CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, 1994 1993 1992 (Thousands of Dollars) Cash Flows From Operating Activities: Net income $151,199 $167,981 $117,590 Adjustments to reconcile net income to net cash provided from operating activities: Depreciation, depletion and amortization 210,905 158,024 126,695 Amortization of nuclear fuel 13,487 18,156 23,190 Deferred income taxes, net 9,967 65,205 (10,783) Deferred investment tax credits, net (3,632) (3,658) (3,667) Net regulatory asset - adoption of SFAS No. 109 (1,951) (31,531) - Dividends declared on preferred stock of subsidiary 5,955 6,217 6,473 Allowance for funds used during construction (15,332) (15,107) (9,766) Unamortized loss on reacquired debt (60) (17,063) (81) Nuclear refueling accrual (4,881) (6,086) 11,862 Equity in (earnings) losses of investees (230) (319) 652 Over (under) collections, fuel adjustment clause (16,966) (14,308) 7,482 Emission allowances (19,409) - - Changes in certain current assets and liabilities: (Increase) decrease in receivables (9,059) (35,244) (8,918) (Increase) decrease in inventories 2,131 (10,995) (234) Increase (decrease) in accounts payable (11,536) 28,109 7,282 Increase (decrease) in estimated rate refunds and related interest (2,509) (15,302) 17,811 Increase (decrease) in taxes accrued (3,393) (14,941) 1,691 Increase (decrease) in interest accrued 3,442 (7,511) 663 Other, net (11,423) 3,955 12,354 Net Cash Provided From Operating Activities 296,705 275,582 300,296 Cash Flows From Investing Activities: Utility property additions and construction expenditures (404,600) (322,381) (277,636) (Increase) decrease in nonutility property and investments: Acquisition of oil and gas producing properties (47,189) (122,621) (74,766) Nonutility property (109,336) (81,044) (35,462) Investments (19,006) (4,066) (2,591) Sale of Real Estate Assets 79,439 - - Principal noncash item: Allowance for funds used during construction 15,332 15,107 9,766 Net Cash Used For Investing Activities (485,360) (515,005) (380,689) Cash Flows From Financing Activities: Proceeds: Issuance of mortgage bonds 100,000 600,000 - Issuance of common stock 63,317 129,066 126,809 Issuance of notes and loans 60,000 148,059 154,254 Issuance of pollution control bonds 30,000 - - Other long-term debt - 3,005 - Repayments: Mortgage bonds - (430,000) (35,890) Notes (75,545) (72,040) (95,272) Other long-term debt (11,430) (1,195) (255) Preferred stock (3,398) (3,295) (3,199) Dividend payments: Common stock (131,925) (122,129) (109,383) Preferred stock (6,048) (6,247) (6,558) Short-term borrowings, net 140,008 1,863 20,390 Fuel financings, net 13,844 (18,948) (6,628) Net Cash Provided By Financing Activities 178,823 228,139 44,268 Net Decrease in Cash and Temporary Cash Investments (9,832) (11,284) (36,125) Cash and Temporary Cash Investments, January 1 20,766 32,050 68,175 Cash and Temporary Cash Investments, December 31 $ 10,934 $ 20,766 $ 32,050 Supplemental Cash Flows Information: Cash paid for - Interest $110,347 $113,010 $100,340 - Income taxes 90,012 93,337 81,819 Noncash Financing Activities: Department of Energy decontamination and decommissioning obligation - 4,965 - See Notes to Consolidated Financial Statements. 43 CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 1994 1993 Common Equity (Note 5): (Thousands of Dollars) Common stock, without par value, authorized 75,000,000 shares; issued and outstanding, 1994 - 48,017,510 shares and 1993 - 46,619,457 shares $ 886,770 $ 826,665 Retained earnings 523,668 506,380 Total Common Equity 1,410,438 46% 1,333,045 47% South Carolina Electric & Gas Company: Cumulative Preferred Stock (Not subject to purchase or sinking funds)(Note 5): $100 Par Value - Authorized 200,000 shares $50 Par Value - Authorized 125,209 shares Shares Outstanding Redemption Price Eventual Series 1994 1993 Current Through Minimum $100 Par 8.40% 197,668 197,668 102.80 11-30-96 101.00 19,767 19,767 $50 Par 5.00% 125,209 125,209 52.50 - 52.50 6,260 6,260 Total Preferred Stock (Not subject to purchase or sinking funds) 26,027 1% 26,027 1% South Carolina Electric & Gas Company: Cumulative Preferred Stock (Subject to purchase or sinking funds)(Notes 6 and 8): $100 Par Value - Authorized 1,550,000 shares Shares Outstanding Redemption Price Eventual Series 1994 1993 Current Through Minimum 7.70% 89,984 92,992 101.00 - 101.00 8,998 9,299 8.12% 126,835 131,899 102.03 - 102.03 12,684 13,190 216,819 224,891 $50 Par Value - Authorized 1,627,074 shares Shares Outstanding Redemption Price Eventual Series 1994 1993 Current Through Minimum 4.50% 19,088 20,800 51.00 - 51.00 954 1,040 4.60% 2,334 3,834 50.50 - 50.50 117 192 4.60%(A) 28,052 30,052 51.00 - 51.00 1,403 1,503 4.60%(B) 78,200 81,600 50.50 - 50.50 3,910 4,080 5.125% 73,000 74,000 51.00 - 51.00 3,650 3,700 6.00% 86,400 89,600 50.50 - 50.50 4,320 4,480 8.72% 127,956 160,000 51.00 12-31-98 50.00 6,398 8,000 9.40% 190,245 197,191 51.175 - 51.175 9,512 9,860 605,275 657,077 $25 Par Value - Authorized 2,000,000 shares; none outstanding in 1994 and 1993 Total Preferred Stock (Subject to purchase or sinking funds) 51,946 55,344 Less: Current portion, including sinking fund requirements 2,418 2,504 Total Preferred Stock, Net (Subject to purchase or sinking funds) 49,528 2% 52,840 2% 44 December 31, 1994 1993 Long-Term Debt (Notes 3, 4 and 8): (Thousands of Dollars) SCANA Corporation: Bank Notes, due 1996 (6.44%, reset quarterly) 60,000 60,000 Medium-term Notes: Year of Series Maturity 5.76% 1998 20,000 20,000 7.17% 1999 42,400 42,400 6.60% 1999 30,000 30,000 6.15% 2000 20,000 20,000 6.51% 2003 20,000 20,000 South Carolina Electric & Gas Company: 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 - 7 1/8% 2013 150,000 150,000 7 1/2% 2023 150,000 150,000 7 5/8% 2023 100,000 100,000 First and Refunding Mortgage Bonds: Year of Series Maturity 4 7/8% 1995 16,000 16,000 5.45% 1996 15,000 15,000 6% 1997 15,000 15,000 6 1/2% 1998 20,000 20,000 7 1/4% 2002 30,000 30,000 9% 2006 145,000 145,000 8 7/8% 2021 155,000 155,000 Pollution Control Facilities Revenue Bonds: 5.95% Series, due 2003 6,660 6,760 Fairfield County Series 1984, due 2014 (6.50%) 56,820 56,820 Richland County Series 1985, due 2014 (6.50%) 5,210 5,210 Fairfield County Series 1986, due 2014 (6.50%) 1,090 1,090 Colleton and Dorchester Counties Series 1987, due 2014 (6.60%) 4,365 4,365 Orangeburg County Series 1994 due 2024 (daily adjusted rate) 30,000 - Capitalized Lease Obligations, due 1991-1997 (various rates between 5 3/4% and 10%) 1,842 2,897 Installment Note Payable, due 1996 1,452 2,277 Department of Energy Decontamination and Decommissioning Obligation 3,922 4,634 South Carolina Generating Company, Inc.: Berkeley County Pollution Control Facilities Revenue Bonds, due 2014 (6.50%) 35,850 35,850 Note, 7.78%, due 2011 67,400 71,100 South Carolina Fuel Company, Inc.: Nuclear and Fossil Fuel Liability 50,594 36,750 South Carolina Pipeline Corporation: Notes, 6.72%, due 2013 23,750 25,000 Note, 9.27%, due 1991-1994 - 8,000 SCANA Development Corporation: Notes, due 1994-2004 (various rates between 8.5% and 12.0%) - 1,770 Bank Loans, due 1994-1998 (various rates between 6% and 6.25%) 3,246 13,839 Total Long-Term Debt 1,580,601 1,464,762 Less - Current maturities, including sinking fund requirements 38,055 34,322 - Unamortized discount 4,922 6,041 Total Long-Term Debt, Net 1,537,624 51% 1,424,399 50% Total Capitalization $3,023,617 100% $2,836,311 100% See Notes to Consolidated Financial Statements. 45 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES: A. Organization and Principles of Consolidation SCANA Corporation (Company), a South Carolina corporation, is a public utility holding company within the meaning of the Public Utility Holding Company Act of 1935 but is exempt from registration under such Act. The accompanying Consolidated Financial Statements reflect the consolidation of the accounts of the Company and its wholly owned subsidiaries: Regulated utilities South Carolina Electric Gas Company (SCE&G) South Carolina Fuel Company, Inc. South Carolina Generating Company, Inc. (GENCO) South Carolina Pipeline Corporation (Pipeline Corporation) Nonregulated businesses SCANA Petroleum Resources, Inc. (Petroleum Resources) SCANA Hydrocarbons, Inc. Suburban Propane Group, Inc. MPX Systems, Inc. (MPX) Primesouth, Inc. ServiceCare, Inc. SCANA Development Corporation SCANA Capital Resources, Inc. Investments in joint ventures in real estate and telecommunications are reported using the equity method of accounting. Significant intercompany balances and transactions have been eliminated in consolidation. In January 1994 the Company signed an agreement to sell substantially all of the real estate assets of SCANA Development Corporation to Liberty Properties Group, Inc. (Liberty) of Greenville, South Carolina for $91.5 million. On March 4, 1994 the Company and Liberty amended the agreement to exclude certain projects then under construction, and the sales price was reduced to $49.6 million. The transaction was closed on May 27, 1994. Certain other assets of SCANA Development Corporation are being sold to other parties. These transactions did not have a material impact on the Company's financial position or results of operations. B. System of Accounts The accounting records of the Company's regulated subsidiaries are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (FERC) and as adopted by the Public Service Commission of South Carolina (PSC). 46 C. Utility Plant Utility plant is stated substantially at original cost. The costs of additions, renewals and betterments to utility plant, including direct labor, material and indirect charges for engineering, supervision and an allowance for funds used during construction, are added to utility plant accounts. The original cost of utility property retired or otherwise disposed of is removed from utility plant accounts and generally charged, along with the cost of removal, less salvage, to accumulated depreciation. The costs of repairs, replacements and renewals of items of property determined to be less than a unit of property are charged to maintenance expense. SCE&G, operator of the V. C. Summer Nuclear Station (Summer Station), and the South Carolina Public Service Authority (PSA) are joint owners of Summer Station in the proportions of two- thirds and one-third, respectively. The parties share the op- erating costs and energy output of the plant in these proportions. Each party, however, provides its own financing. Plant in service related to SCE&G's portion of Summer Station was approximately $923.1 million and $920.2 million as of December 31, 1994 and 1993, respectively. Accumulated depreciation associated with SCE&G's share of Summer Station was approximately $297.9 million and $285.3 million as of December 31, 1994 and 1993, respectively. SCE&G's share of the direct expenses associated with operating Summer Station is included in "Other operation" and "Maintenance" expenses. D. Allowance for Funds Used During Construction Allowance for funds used during construction (AFC), a noncash item, reflects the period cost of capital devoted to plant under construction. This accounting practice results in the inclusion, as a component of construction cost, of the costs of debt and equity capital dedicated to construction investment. AFC is included in rate base investment and depreciated as a component of plant cost in establishing rates for utility services. The Company's regulated subsidiaries calculated AFC using composite rates of 8.5%, 9.3% and 9.6% for 1994, 1993 and 1992, respectively. These rates do not exceed the maximum allowable rate as calculated under FERC Order No. 561. Interest on nuclear fuel in process and sulfur dioxide emission allowances is capitalized at the actual interest amount. E. Deferred Return on Plant Investment Commencing July 1, 1987, as approved by a PSC order on that date, SCE&G ceased the deferral of carrying costs associated with 400 MW of electric generating capacity previously removed from rate base and began amortizing the accumulated deferred carrying costs on a straight-line basis over a ten-year period. Amortization of deferred carrying costs, included in "Depreciation and amortization," was approximately $4.2 million for each of 1994, 1993 and 1992. F. Revenue Recognition Customers' meters are read and bills are rendered on a monthly cycle basis. Base revenue is recorded during the accounting period in which the meters are read. Fuel costs for electric generation are collected through the fuel cost component in retail electric rates. The fuel cost component contained in electric rates is established by the PSC during semiannual fuel cost hearings. Any difference between actual fuel costs and that contained in the fuel cost component is deferred and included when determining the fuel cost component during the next semiannual fuel cost hearing. SCE&G had undercollected through the electric fuel cost component approximately $3.5 million at December 31, 1994 and overcollected approximately $9.2 million at December 31, 1993 which are included in "Deferred Debits-Other" and "Deferred Credits-Other", respectively. 47 Customers subject to the gas cost adjustment clause are billed based on a fixed cost of gas determined by the PSC during annual gas cost recovery hearings. Any difference between actual gas cost and that contained in the rates is deferred and included when establishing gas costs during the next annual gas cost recovery hearing. At December 31, 1994 and 1993 the Company had undercollected through the gas cost recovery procedure approximately $16.3 million and $12.0 million, respectively, which are included in "Deferred Debits-Other." G. Depreciation, Depletion 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 as follows: 1994 1993 1992 SCE&G 3.01% 2.97% 3.00% GENCO 2.70% 2.64% 2.63% Pipeline Corporation 2.79% 2.62% 2.62% Aggregate of Above 2.98% 2.92% 2.96% Nuclear fuel amortization, which is included in "Fuel used in electric generation" and is recovered through the fuel cost component of SCE&G's rates, is recorded using the units-of- production method. Provisions for amortization of nuclear fuel include amounts necessary to satisfy obligations to the United States Department of Energy under a contract for disposal of spent nuclear fuel. The acquisition adjustment relating to the purchase of certain gas properties in 1982 is being amortized over a 40-year period using the straight-line method. Depreciation, depletion and amortization (DD&A) of the capitalized costs of oil and gas producing properties is provided for on the units-of-production basis. Units-of-production rates are based on estimated proved reserves. H. Nuclear Decommissioning Decommissioning of Summer Station is presently projected to commence in the year 2022 when the operating license expires. The expenditures (on a before-tax basis) related to SCE&G's share of decommissioning activities are currently estimated, in 2022 dollars assuming a 4.5% annual rate of inflation, to be $545.3 million including partial reclamation costs. SCE&G is providing for its share of estimated decommissioning costs of Summer Station over the life of Summer Station. SCE&G'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 and $2.5 million in 1994 and 1993, respectively) are used to purchase insurance policies on the lives of key Company personnel. Through the purchase of insurance contracts, SCE&G 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 SCE&G to an external trust fund in compliance with the financial assurance requirements of the Nuclear Regulatory Commission. Management intends for the fund, including earnings thereon, to provide for all eventual decommissioning expenditures on an after-tax basis. Thus, the trust's sources of decommissioning funds under the COMReP program include investment components of life insurance policy proceeds, return on investments, and the cash transfers from SCE&G described above. SCE&G records its liability for decommissioning costs in deferred credits. 48 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 financial statements of electric utilities with nuclear generating facilities. In response to these questions, the Financial Accounting Standards Board has agreed to review the accounting for removal costs, including decommissioning. If the current electric utility industry accounting practices for such decommissioning are changed: (1) annual provisions for decommissioning could increase, and (2) trust fund income from the external decommissioning trusts could be reported as investment income rather than as a reduction of decommissioning expense. In addition, pursuant to the National Energy Policy Act passed by Congress in 1992, SCE&G has recorded a liability for its estimated share of amounts required by the U.S. Department of Energy for its decommissioning fund. SCE&G will recover the costs associated with this liability, totaling $4.3 million at December 31, 1994, through the fuel cost component of its rates; accordingly, these amounts have been deferred and are included in "Deferred Debits-Other" and "Long-Term Debt, Net." I. Income Taxes The Company and its subsidiaries file consolidated Federal and State income tax returns. Income taxes are allocated to all subsidiaries based on their contributions to consolidated taxable income. The Company adopted Statement of Financial Accounting Standards No. 109, "Accounting for Income Taxes," effective January 1, 1993. Prior years' financial statements have not been restated. Deferred tax assets and liabilities were adjusted from the amounts recorded at December 31, 1992 under prior standards to the amounts required at January 1, 1993 under Statement No. 109 at currently enacted income tax rates. The adjustments were charged or credited to regulatory assets or liabilities if the Company expected to recover the resulting additional income tax expense from, or pass through the resulting reductions in income tax expense to, customers of the Company's regulated subsidiaries; otherwise, they were charged or credited to income tax expense. The cumulative effect of adopting Statement No. 109 on retained earnings as of January 1, 1993, as well as the effect of adoption on net income for the year ended December 31, 1993, was not material. At December 31, 1993 the combined effect of adopting Statement No. 109 and adjusting deferred tax assets and liabilities for the change in 1993 of the corporate Federal income tax rate from 34% to 35% resulted in balances of $100.8 million in regulatory assets (included in "Deferred Debits- Other") and $69.3 million in regulatory liabilities (included in "Deferred Credits-Other") for the Company's regulated subsidiaries. In accordance with Statement No. 109, deferred tax assets and liabilities are recorded for the tax effects of temporary differences between the book basis and tax basis of assets and liabilities at currently enacted tax rates. Deferred tax assets and liabilities are adjusted for changes in such rates through charges or credits to regulatory assets or liabilities if they are expected to be recovered from, or passed through to, customers of the Company's regulated subsidiaries; otherwise, they are charged or credited to income tax expense. Prior to the adoption of Statement No. 109 on January 1, 1993, the Company recorded a deferred income tax provision on all material timing differences between the inclusion of items in pretax financial income and taxable income each year, except for those which were expected to be passed through to, or collected from, customers of the Company's regulated subsidiaries. Accumulated deferred income taxes were generally not adjusted for changes in enacted tax rates. 49 J. Pension Expense The Company has a noncontributory defined benefit pension plan covering substantially all permanent employees. Benefits are based on years of accredited service and the employee's average annual base earnings received during the last three years of employment. The Company's policy has been to fund pension costs accrued to the extent permitted by the applicable Federal income tax regulations as determined by an independent actuary. Net periodic pension cost for the years ended December 31, 1994, 1993 and 1992 included the following components: 1994 1993 1992 (Thousands of Dollars) Service cost--benefits earned during the period $ 8,684 $ 7,629 $ 7,174 Interest cost on projected benefit obligation 21,711 20,413 19,628 Adjustments: Return on plan assets 2,365 (50,389) (28,607) Net amortization and deferral (29,760) 25,936 8,096 Net periodic pension cost $ 3,000 $ 3,589 $ 6,291 The determination of net periodic pension cost is based upon the following assumptions: 1994 1993 1992 Annual discount rate 7.25% 8.0% 8.0% Expected long-term rate of return on plan assets 8.0% 8.0% 8.0% Annual rate of salary increases 4.75% 5.5% 5.5% The following table sets forth the funded status of the plan at December 31, 1994 and 1993: 1994 1993 (Thousands of Dollars) Actuarial present value of benefit obligations: Vested benefit obligation $205,364 $204,794 Nonvested benefit obligation 13,966 14,085 Accumulated benefit obligation $219,330 $218,879 Plan assets at fair value (invested primarily in equity and debt securities) $347,702 $351,648 Projected benefit obligation 246,318 295,718 Plan assets greater than projected benefit obligation 101,384 55,930 Unrecognized net transition liability 11,307 10,713 Unrecognized prior service costs 9,374 9,294 Unrecognized net gain (102,284) (64,607) Pension asset recognized in Consolidated Balance Sheets $ 19,781 $ 11,330 50 The accumulated benefit obligation is based on the plan's benefit formulas without considering expected future salary increases. The following table sets forth the assumptions used in determining the amounts shown above for the years 1994, 1993 and 1992. 1994 1993 1992 Annual discount rate used to determine benefit obligations 8.0% 7.25% 8.0% Assumed annual rate of future salary increases for projected benefit obligation 2.5% 4.75% 5.5% The change in the annual discount rate used to determine benefit obligations from 7.25% to 8.0% and the change in the expected salary increase rate from 4.75% to 2.5% as of December 31, 1994 decreased the projected benefit obligation and increased the unrecognized net gain by approximately $67.7 million. In addition to pension benefits, the Company provides certain health care and life insurance benefits to active and retired employees. The costs of postretirement benefits other than pensions are accrued during the years the employees render the service necessary to be eligible for the applicable benefits. Prior to 1993, the Company expensed these benefits, which are primarily health care, as claims were incurred. In its June 1993 electric rate order the PSC approved the inclusion in rates of the portion of increased expenses related to electric operations. The Company expensed approximately $8.6 million and $4.3 million, net of payments to current retirees, for the years ended December 31, 1994 and 1993, respectively. Net periodic postretirement benefit cost for the years ended December 31, 1994 and 1993, included the following components: 1994 1993 (Thousands of Dollars) Service cost--benefits earned during the period $ 2,417 $ 1,908 Interest cost on accumulated postretirement benefit obligation 6,644 5,502 Adjustments: Return on plan assets - - Amortization of unrecognized transition obligation 3,344 3,344 Other net amortization and deferral 860 - Net periodic postretirement benefit cost $13,265 $10,754 The determination of net periodic postretirement benefit cost is based upon the following assumptions: 1994 1993 Annual discount rate 7.25% 8.0% Health care cost trend rate 11.25% 13.0% Ultimate health care cost trend rate (to be achieved in 2004) 5.25% 6.0% 51 The following table sets forth the funded status of the plan at December 31, 1994 and 1993: 1994 1993 (Thousands of Dollars) Accumulated postretirement benefit obligations for: Retirees $ 59,174 $ 40,865 Other fully eligible participants 4,995 6,841 Other active participants 24,889 25,767 Accumulated postretirement benefit obligation 89,058 73,473 Plan assets at fair value - - Plan assets less accumulated postretirement benefit obligation (89,058) (73,473) Unrecognized net transition liability 61,581 64,925 Unrecognized prior service costs 3,453 - Unrecognized net loss 11,156 4,284 Postretirement benefit liability recognized in Consolidated Balance Sheets $(12,868) $ (4,264) The accumulated postretirement benefit obligation is based upon the plan's benefit provisions and the following assumptions: 1994 1993 Assumed health care cost trend rate used to measure expected costs 12.0% 11.25% Ultimate health care cost trend rate (to be achieved in 2004) 6.0% 5.25% Annual discount rate 8.0% 7.25% Annual rate of salary increases 2.5% 4.75% The effect of a one-percentage-point increase in the assumed health care cost trend rate for each future year on the aggregate of the service and interest cost components of net periodic postretirement benefit cost for the year ended December 31, 1994 and the accumulated postretirement benefit obligation as of December 31, 1994 would be to increase such amounts by $210,000 and $3.3 million, respectively. K. Debt Premium, Discount and Expense, Unamortized Loss on Reacquired Debt Long-term debt premium, discount and expense are being amortized as components of "Interest on long-term debt, net" over the terms of the respective debt issues. Gains or losses on reacquired debt that is refinanced are deferred and amortized over the term of the replacement debt. L. Environmental The Company has an environmental assessment program to identify and assess current and former operations sites that could require environmental cleanup. As site assessments are initiated, an estimate is made of the amount of expenditures, if any, necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations; such amounts have been deferred and are being amortized and recovered through rates over a ten-year period for electric operations and an eight-year period for gas operations. Such deferred amounts totaled $20.2 million and $19.6 million at December 31, 1994 and 1993, respectively, and are included in "Deferred Debits-Other." 52 M. Oil and Gas Oil and gas properties are accounted for using the successful-efforts method. The costs of acquiring nonproducing acreage, drilling successful exploration wells, and all development costs are capitalized. The Company's net investment in oil and gas properties is subject to a quarterly ceiling limitation calculation that is based on the future net revenues from forecasted production of proved oil and gas reserves valued at current or contract prices. Carrying value of proved reserves in excess of the ceiling limitation are expensed currently. The Company's investments in nonproducing properties are evaluated periodically, and if conditions warrant, an impairment reserve is provided. Cost of that portion of undeveloped acreage likely to be unproductive, based largely on historical experience, are amortized over the period of exploration. Annual lease rentals and exploration costs, including geological and geophysical costs and exploratory dry-hole cost, are expensed as incurred. N. Gas Futures Contracts The Company sells gas futures and forward contracts, purchases options, and enters into over-the-counter agreements to hedge price risks for the majority of Petroleum Resources' production. Gains and losses on the above are recognized concurrently with the revenue from the associated gas sales. O. Temporary Cash Investments The Company considers temporary cash investments having original maturities of three months or less to be cash equivalents. Temporary cash investments are generally in the form of commercial paper, certificates of deposit and repurchase agreements. P. Reclassifications Certain amounts from prior periods have been reclassified to conform with the 1994 presentation. 2. RATE MATTERS: A. On October 27, 1994 the PSC issued an order approving SCE&G'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, provides for the recovery of approximately $16.2 million representing substantially all site assessment and cleanup costs for SCE&G's gas operations that had previously been deferred. B. On June 7, 1993 the PSC issued an order on SCE&G's pending electric rate proceeding allowing an authorized return on common equity of 11.5%, resulting in a 7.4% annual increase in retail electric rates, or a projected $60.5 million annually, based on a test year. These rates were implemented in two phases over a two-year period: phase one, effective June 1993, producing $42.0 million annually, and phase two, effective June 1994, producing $18.5 million annually, based on a test year. C. On September 14, 1992 the PSC issued an order granting SCE&G 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 SCE&G's request to reduce the number of routes and frequency of service. The new rates were placed into effect on October 5, 1992. SCE&G has appealed the PSC's order to the Circuit Court. 53 D. Effective with the first billing cycle in December 1991, SCE&G's gas rate schedules for its residential, small commercial and small industrial customers have included a weather normalization adjustment (WNA). The WNA minimizes fluctuations in gas revenues due to abnormal weather conditions and is subject to annual review by the PSC. The PSC order was based on a return on common equity of 12.25%. On August 26, 1994, the PSC ordered that the WNA be made permanent. E. In May 1989 the PSC approved a volumetric and direct billing method for Pipeline Corporation to recover take-or-pay costs incurred from its interstate pipeline suppliers pursuant to FERC-approved final and nonappealable settlements. In December 1992 the Supreme Court approved Pipeline Corporation's full recovery of the take-or-pay charges imposed by its suppliers and treatment of these charges as a cost of gas. However, the Supreme Court declared the PSC-approved "purchase deficiency" methodology for recovery of these costs to be unlawful retroactive ratemaking and remanded the docket to the PSC to reconsider its recovery methodology. On April 30, 1994 the PSC issued an order involving Pipeline Corporation's recovery of take-or-pay cost incurred pursuant to FERC-approved settlements with its upstream interstate pipeline supplier. This order provided a mechanism for Pipeline Corporation to recover its take-or-pay cost volumetrically over a period of approximate 30 months. SCE&G receives a credit for payments made prior to the April 30 order which is netted against the current volumetric surcharge. That net cost is recovered by SCE&G through its purchased gas adjustment clause. F. On August 8, 1990 the PSC issued an order, effective November 1, 1990, approving changes in Pipeline Corporation's gas rate design for sales for resale service and upholding the "value-of-service" method of regulation for its direct industrial service. Direct industrial customers seeking "cost-of-service" based rates initiated two separate appeals to the Circuit Court, which reversed and remanded to the PSC its August 8, 1990 order. Pipeline Corporation appealed that decision to the Supreme Court which, on January 10, 1994, reversed the two Circuit Court decisions and reinstated the PSC Order. The Supreme Court held that the industrial customer group's appeal was premature and failed to exhaust administrative remedies. Additionally, the Supreme Court interpreted the rate-making statutes of South Carolina to give discretion to the PSC in selecting the methodology to be used in setting rates for natural gas service. G. On July 3, 1989 the PSC granted SCE&G approximately $21.9 million of a requested $27.2 million annual increase in retail electric revenues based upon an allowed return on common equity of 13.25%. The Consumer Advocate appealed the decision to the Supreme Court which, on August 31, 1992, found that the evidence in the record of that case did not support a return on common equity higher than 13.0% and remanded to the PSC a portion of its July 1989 order for a determination of the proper return on common equity consistent with the Supreme Court's opinion. On January 19, 1993 the PSC issued an order allowing a return on common equity of 13.0%, approving a refund based on the difference in rates created by the difference between the 13.0% and the 13.25% return on common equity and making other nonmaterial adjustments to the calculation of cost-of-service. The total refund, before interest and income taxes, was approximately $14.6 million and was charged against 1992 "Electric Revenues." The refund plus interest was made during 1993. 54 3. LONG-TERM DEBT: The annual amounts of long-term debt maturities, including the amounts due under the nuclear and fossil fuel agreement (see Note 4), and sinking fund requirements for the years 1995 through 1999 are summarized as follows: Year Amount Year Amount (Thousands of Dollars) 1995 $ 38,055 1998 $60,174 1996 147,248 1999 92,584 1997 38,306 Approximately $14.8 million of the portion of long-term debt payable in 1995 may be satisfied by either deposit and cancellation of bonds issued upon the basis of property additions or bond retirement credits, or by deposit of cash with the Trustee. In January 1995 the Company arranged for an unsecured bank loan of $60 million, due January 12, 1996 at an initial interest rate of 6.44%, subject to reset quarterly at LIBOR plus ten basis points. Proceeds from the loans were used to repay bank loans totaling $60 million due January 13, 1995; accordingly, such loans are included in long-term debt at December 31, 1994. Substantially all utility plant and fuel inventories are pledged as collateral in connection with long-term debt. 4. FUEL FINANCINGS: Nuclear and fossil fuel inventories are financed through the issuance of short-term commercial paper. These short-term borrowings are supported by an irrevocable revolving credit agreement which expires July 31, 1996. Accordingly, the amounts outstanding have been included in long-term debt. The credit agreement provides for a maximum amount of $75 million that may be outstanding at any time. Commercial paper outstanding totaled $50.6 million and $36.8 million at December 31, 1994 and 1993 at weighted average interest rates of 6.06% and 3.47%, respectively. 5. STOCKHOLDERS' INVESTMENT (Including Preferred Stock Not Subject to Purchase or Sinking Funds): The changes in "Common Stock," without par value, during 1994, 1993 and 1992 are summarized as follows: Number Thousands of Shares of Dollars Balance December 31, 1991 40,784,327 $571,597 Issuance of common stock 3,126,304 127,406 Balance December 31, 1992 43,910,631 699,003 Issuance of common stock 2,708,826 127,662 Balance December 31, 1993 46,619,457 826,665 Issuance of common stock 1,398,053 60,105 Balance December 31, 1994 48,017,510 $886,770 55 The Restated Articles of Incorporation of the Company do not limit the dividends that may be payable on its common stock. However, the Restated Articles of Incorporation of SCE&G and the Indenture underlying its First and Refunding Mortgage Bonds contain provisions that may limit the payment of cash dividends on its common stock. In addition, with respect to hydroelectric projects, the Federal Power Act may require the appropriation of a portion of the earnings therefrom. At December 31, 1994 approximately $13.2 million of retained earnings were restricted as to payment of cash dividends on common stock. Cash dividends on common stock were declared at an annual rate per share of $2.82, $2.74 and $2.68 for 1994, 1993 and 1992, respectively. 6. PREFERRED STOCK (Subject to Purchase or Sinking Funds): The call premium of the respective series of preferred stock in no case exceeds the amount of the annual dividend. Retirements under sinking fund requirements are at par values. At any time when dividends have not been paid in full or declared and set apart for payment on all series of preferred stock, SCE&G may not redeem any shares of preferred stock (unless all shares of preferred stock then outstanding are redeemed) or purchase or otherwise acquire for value any shares of preferred stock except in accordance with an offer made to all holders of preferred stock. SCE&G may not redeem any shares of preferred stock (unless all shares of preferred stock then outstanding are redeemed) or purchase or otherwise acquire for value any shares of preferred stock (except out of monies set aside as purchase funds or sinking funds for one or more series of preferred stock) at any time when it is in default under the provisions of the purchase fund or sinking fund for any series of preferred stock. The aggregate annual amounts of purchase fund or sinking fund requirements for preferred stock for the years 1995 through 1999 are summarized as follows: Year Amount Year Amount (Thousands of Dollars) 1995 $2,418 1998 $2,440 1996 2,482 1999 2,440 1997 2,440 The changes in "Total Preferred Stock (Subject to purchase or sinking funds)" during 1994, 1993 and 1992 are summarized as follows: Number Thousands of Shares of Dollars Balance December 31, 1991 998,404 $61,838 Shares Redeemed: $100 par value (6,098) (610) $50 par value (51,777) (2,589) Balance December 31, 1992 940,529 58,639 Shares Redeemed: $100 par value (7,374) (737) $50 par value (51,187) (2,558) Balance December 31, 1993 881,968 55,344 Shares Redeemed: $100 par value (8,072) (807) $50 par value (51,802) (2,591) Balance December 31, 1994 822,094 $51,946 56 7. INCOME TAXES: Total income tax expense for 1994, 1993 and 1992 is as follows: 1994 1993 1992 (Thousands of Dollars) Current taxes: Federal $62,033 $59,590 $67,240 State 13,178 6,409 8,146 Total current taxes 75,211 65,999 75,386 Deferred taxes, net: Federal 10,242 23,219 (11,888) State (86) 6,003 413 Total deferred taxes 10,156 29,222 (11,475) Investment tax credits: Amortization of amounts deferred (credit) (3,631) (3,659) (3,659) Total income tax expense $81,736 $91,562 $60,252 The difference in actual income taxes and the income taxes calculated from the application of the statutory Federal income tax rate (35% for 1994 and 1993 and 34% for 1992) to pretax income is reconciled as follows: 1994 1993 1992 (Thousands of Dollars) Net income $151,199 $167,981 $117,590 Total income tax expense: Charged to operating expenses 94,510 90,007 60,947 Charged (credited) to other income (12,774) 1,555 (695) Preferred stock dividends 5,955 6,217 6,473 Total pretax income $238,890 $265,760 $184,315 Income taxes on above at statutory Federal income tax rate $ 83,612 $ 93,016 $ 62,667 Increases (decreases) attributable to: Allowance for funds used during construction (excluding nuclear fuel) (2,862) (3,125) (1,868) Deferred return on plant investment, net of amortization 1,486 1,486 1,444 Depreciation differences 2,860 2,794 2,129 Amortization of investment tax credits (3,631) (3,659) (3,659) State income taxes (less Federal income tax effect) 8,510 8,068 5,649 Deferred income tax flowback at higher than statutory rates (4,327) (4,411) (5,565) Alternate fuel production tax credit (1,274) (1,373) (275) Other differences, net (2,638) (1,234) (270) Total income tax expense $ 81,736 $ 91,562 $ 60,252 The Omnibus Budget Reconciliation Act was signed into law on August 10, 1993, increasing the corporate tax rate from 34% to 35% effective January 1, 1993. The impact of this change on the Company's financial position and results of operations was not material. 57 The tax effects of significant temporary differences comprising the Company's net deferred tax liability of $570.4 million at December 31, 1994 and $559.6 million at December 31, 1993 determined in accordance with Statement No. 109 (see Note 1I) are as follows: 1994 1993 (Thousands of Dollars) Deferred tax assets: Unamortized investment tax credits $ 56,588 $ 58,839 Cycle billing 17,521 15,084 Nuclear operations expenses 206 4,908 Deferred compensation 5,513 5,315 Other post retirement benefits 3,187 1,631 Other 8,392 11,102 Total deferred tax assets 91,407 96,879 Deferred tax liabilities: Property, plant and equipment (including DD&A and basis differences) 625,636 619,859 Pension expense 9,022 6,266 Deferred fuel revenue 7,803 931 Reacquired debt 7,146 7,574 Other 12,197 21,814 Total deferred tax liabilities 661,804 656,444 Net deferred tax liability $570,397 $559,565 "Total deferred taxes" charged (credited) to income tax expense result from timing differences in recognition of the following items (thousands of dollars): 1992 Charged (credited) to expense: Property, plant and equipment (including DD&A and basis differences) $ 7,435 Deferred fuel revenue (2,958) Property taxes 562 Cycle billing (1,321) Take-or-pay contracts (1,118) Nuclear refueling accrual (4,430) Electric rate refund (6,571) Injuries and damages (1,377) Other, net (1,697) Total deferred taxes $(11,475) The Internal Revenue Service has examined and closed consolidated Federal income tax returns of the Company through 1989 and is currently examining the 1990, 1991 and 1992 Federal income tax returns. No adjustments are currently proposed by the examining agent. The Company 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. 58 8. FINANCIAL INSTRUMENTS: The carrying amounts and estimated fair values of the Company's financial instruments at December 31, 1994 and 1993 are as follows: 1994 1993 Estimated Estimated Carrying Fair Carrying Fair Amount Value Amount Value (Thousands of Dollars) Cash and temporary cash investments $ 10,934 $ 10,934 $ 20,766 $ 20,766 Investments 24,858 27,099 5,312 15,235 Short-term borrowings 183,027 183,027 43,019 43,019 Total long-term debt 1,575,679 1,490,852 1,458,721 1,551,873 Total preferred stock (subject to purchase or sinking funds) 51,946 49,348 55,344 51,618 The information presented herein is based on pertinent information available to the Company as of December 31, 1994 and 1993. Although the Company is not aware of any factors that would significantly affect the estimated fair value amounts, such financial instruments have not been comprehensively revalued since December 31, 1994, and the current estimated fair value may differ significantly from the estimated fair value at that date. The following methods and assumptions were used to estimate the fair value of the above classes of financial instruments: Cash and temporary cash investments, including commercial paper, repurchase agreements, treasury bills and notes are valued at their carrying amount. Fair values of investments and long-term debt are based on quoted market prices for similar instruments, or for those instruments for which there are no quoted market prices available, fair values are based on net present value calculations. Investments which are not considered to be financial instruments (goodwill) have been excluded from the carrying amount and estimated fair value. Settlement of long- term debt may not be possible or may not be a prudent management decision. Short-term borrowings are valued at their carrying amount. The fair value of preferred stock (subject to purchase or sinking funds) is estimated on the basis of market prices. Potential taxes and other expenses that would be incurred in an actual sale or settlement have not been taken into consideration. 9. SHORT-TERM BORROWINGS: The Company pays fees to banks as compensation for its lines of credit. Commercial paper borrowings are for 270 days or less. Details of lines of credit and short-term borrowings at December 31, 1994, 1993 and 1992 and for the years then ended are as follows: 1994 1993 1992 (Millions of Dollars) Authorized lines of credit at year-end $479.1 $335.0 $288.9 Unused lines of credit at year-end $455.1 $308.0 $262.8 Short-term borrowings outstanding at year-end: Bank loans $ 71.1 $ 42.0 $ 41.1 Weighted average interest rate 6.50% 3.71% 4.49% Commercial paper $111.2 $ 1.0 - Weighted average interest rate 6.04% 3.35% - 59 10. COMMITMENTS AND CONTINGENCIES: A. Construction SCE&G entered into a contract with Duke/Fluor Daniel in 1991 to design, engineer and build a 385 MW coal-fired electric generating plant near Cope, South Carolina in Orangeburg County. Construction of the plant began in November 1992 and is expected to be complete in late 1995 with commercial operation beginning in early 1996. The estimated cost of the Cope plant, excluding financing costs and AFC but including an allowance for escalation, is $450 million. In addition, the transmission lines for interconnection with SCE&G's system are expected to cost $26 million. Under the Duke/Fluor Daniel contract SCE&G must make specified monthly minimum payments. These minimum payments do not include amounts for inflation on a portion of the contract which is subject to escalation (approximately 34% of the total contract amount). The aggregate amount of such required minimum payments remaining at December 31, 1994 is as follows (thousands of dollars): 1995 $ 59,766 1996 5,603 Total $ 65,369 Through December 31, 1994 SCE&G had paid $310 million under the contract. B. Nuclear Insurance The Price-Anderson Indemnification Act, which deals with public liability for a nuclear incident, currently establishes the liability limit for third-party claims associated with any nuclear incident at $8.9 billion. Each reactor licensee is currently liable for up to $79.3 million per reactor owned for each nuclear incident occurring at any reactor in the United States, provided that not more than $10 million of the liability per reactor would be assessed per year. SCE&G'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. SCE&G currently maintains policies (for itself and on behalf of the PSA) with Nuclear Electric Insurance Limited (NEIL) and American Nuclear Insurers (ANI) providing combined property and decontamination insurance coverage of $1.4 billion for any losses in excess of $500 million pursuant to existing primary coverages (with ANI) on Summer Station. SCE&G pays annual premiums and, in addition, could be assessed a retroactive premium not to exceed 7 1/2 times its annual premium in the event of property damage loss to any nuclear generating facilities covered by NEIL. Based on the current annual premium, this retroactive premium would not exceed $8.2 million. To the extent that insurable claims for property damage, decontamination, repair and replacement and other costs and expenses arising from a nuclear incident at Summer Station exceed the policy limits of insurance, or to the extent such insurance becomes unavailable in the future, and to the extent that SCE&G's rates would not recover the cost of any purchased replacement power, SCE&G will retain the risk of loss as a self-insurer. SCE&G has no reason to anticipate a serious nuclear incident at Summer Station. If such an incident were to occur, it could have a materially adverse impact on the Company's financial position. 60 C. Environmental As described in Note 1L of Notes to Consolidated Financial Statements, the Company has an environmental assessment program to identify and assess current and former operations sites that could require environmental cleanup. As site assessments are initiated, an estimate is made of the amount of expenditures, if any, necessary to investigate and clean up each site. These estimates are refined as additional information becomes available; therefore, actual expenditures could differ significantly from the original estimates. Amounts estimated and accrued to date for site assessments and cleanup relate primarily to regulated operations; such amounts have been deferred and are being amortized and recovered through rates over a ten-year period for electric operations and an eight-year period for gas operations. In September 1992 the Environmental Protection Agency (EPA) notified SCE&G, the City of Charleston and the Charleston Housing Authority of their potential liability for the investigation and cleanup of the Calhoun Park Area Site in Charleston, South Carolina. This site originally encompassed approximately 18 acres and included properties which were the locations for industrial operations, including a wood preserving (creosote) plant and one of SCE&G's decommissioned manufactured gas plants. The original scope of this investigation has been expanded to approximately 30 acres, including adjacent properties owned by the National Park Service and the City of Charleston, and private properties. The site has not been placed on the National Priority List, but may be added before cleanup is initiated. The potentially responsible parties (PRP) have agreed with the EPA to participate in an innovative approach to site investigation and cleanup called "Superfund Accelerated Cleanup Model," allowing the pre-cleanup site investigations process to be compressed significantly. The PRPs have negotiated an administrative order by consent for the conduct of a Remedial Investigation/Feasibility Study (RI/FS) and a corresponding Scope of Work. Actual field work began November 1, 1993 after final approval and authorization was granted by EPA. SCE&G 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 SCE&G that it considers SCE&G 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. SCE&G believes it has meritorious defenses against this claim and does not expect its resolution to have a material impact on its financial position or results of operations. D. Emission Allowances The Company has entered into an agreement with a broker of sulfur dioxide emission allowances to purchase $6.8 million of allowances at a fixed price during 1995. E. Personal Communication Services licenses MPX is pursuing Personal Communication Services licenses for wireless communications in the Southeast through a joint venture. A $40 million construction loan obtained by the joint venture has been guaranteed by SCANA Corporation. F. Oil and Gas Forward Contracts In an effort to limit exposure to changing natural gas prices and to avoid a write-down resulting from the application of the ceiling test (see Note 1M) at December 31, 1994, in January 1995 the Company entered into a series of forward contracts relating to natural gas production. These forward contracts have the effect of stabilizing the price that the Company will receive on approximately sixty percent of its forecasted natural gas production for the years 1995-2001. The forward contracts are at an average price of $1.88 per dekatherm. 61 11. SEGMENT OF BUSINESS INFORMATION: Segment information at December 31, 1994, 1993 and 1992 and for the years then ended is as follows: 1994 Electric Gas Transit Total (Thousands of Dollars) Operating revenues $975,388 $342,672 $ 4,002 $1,322,062 Operating expenses, excluding depreciation and amortization 640,528 292,227 10,577 943,332 Depreciation and amortization 102,647 16,304 226 119,177 Total operating expenses 743,175 308,531 10,803 1,062,509 Operating income (loss) $232,213 $ 34,141 $ (6,801) 259,553 Add - Other income, net 5,998 Less - Interest charges 108,397 - Preferred stock dividends 5,955 Net income $ 151,199 Capital expenditures: Identifiable $364,007 $ 20,079 $ 347 $ 384,433 Utilized for overall Company operations 20,167 Total $ 404,600 Identifiable assets at December 31, 1994: Utility plant, net $2,897,954 $315,746 $ 1,791 $3,215,491 Inventories 98,669 17,026 495 116,190 Total $2,996,623 $332,772 $ 2,286 3,331,681 Other assets 1,061,447 Total assets $4,393,128 62 1993 Electric Gas Transit Total (Thousands of Dollars) Operating revenues $ 940,121 $320,195 $ 3,851 $1,264,167 Operating expenses, excluding depreciation and amortization 621,339 274,936 9,737 906,012 Depreciation and amortization 97,849 14,820 175 112,844 Total operating expenses 719,188 289,756 9,912 1,018,856 Operating income (loss) $ 220,933 $ 30,439 $(6,061) 245,311 Add - Other income, net 30,076 Less - Interest charges 101,189 - Preferred stock dividends 6,217 Net income $ 167,981 Capital expenditures: Identifiable $ 279,082 $ 28,761 $ 604 $ 308,447 Utilized for overall Company operations 13,934 Total $ 322,381 Identifiable assets at December 31, 1993: Utility plant, net $2,628,374 $312,437 $ 1,673 $2,942,484 Inventories 77,805 22,019 463 100,287 Total $2,706,179 $334,456 $ 2,136 3,042,771 Other assets 997,755 Total assets $4,040,526 63 1992 Electric Gas Transit Total (Thousands of Dollars) Operating revenues $ 829,477 $305,275 $ 3,623 $1,138,375 Operating expenses, excluding depreciation and amortization 554,897 256,178 9,205 820,280 Depreciation and amortization 93,978 14,174 163 108,315 Total operating expenses 648,875 270,352 9,368 928,595 Operating income (loss) $ 180,602 $ 34,923 $(5,745) 209,780 Add - Other income, net 11,883 Less - Interest charges 97,600 - Preferred stock dividends 6,473 Net income $ 117,590 Capital expenditures: Identifiable $ 234,918 $ 33,495 $ 346 $ 268,759 Utilized for overall Company operations 8,877 Total $ 277,636 Identifiable assets at December 31, 1992: Utility plant, net $2,456,691 $299,591 $ 1,240 $2,757,522 Inventories 82,717 8,155 481 91,353 Total $2,539,408 $307,746 $ 1,721 2,848,875 Other assets 708,846 Total assets $3,557,721 64 12. QUARTERLY FINANCIAL DATA (UNAUDITED): 1994 First Second Third Fourth Quarter Quarter Quarter Quarter Annual Total operating revenues (000) $347,309 $296,046 $361,329 $317,378 $1,322,062 Operating income (000) 69,398 50,048 86,708 53,399 259,553 Net income (000) 50,124 29,167 49,690 22,218 151,199 Earnings per weighted average share of common stock as reported 1.07 .62 1.04 .46 3.19 1993 First Second Third Fourth Quarter Quarter Quarter Quarter Annual Total operating revenues (000) $321,840 $280,382 $359,453 $302,492 $1,264,167 Operating income (000) 63,714 45,370 84,638 51,589 245,311 Net income (000) 45,110 26,909 64,427 31,535 167,981 Earnings per weighted average share of common stock as reported 1.02 .61 1.41 .68 3.72 65 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE Not Applicable PART III The information required by Item 10, "Directors and Executive Officers of the Registrant," with respect to executive officers is, pursuant to General Instruction G(3) to Form 10-K, set forth in Part I of this Form 10-K under the heading "Executive Officers of the Registrant" on page 25 herein. The other information required by Item 10, as well as that called for by Item 11, "Executive Compensation," Item 12, "Security Ownership of Certain Beneficial Owners and Management" and Item 13, "Certain Relationships and Related Transactions" is incorporated herein by reference to the captions "Election of Directors - Proposal 1," "Security Ownership of Certain Beneficial Owners and Management," "Compensation of Directors," Compensation Committee Interlocks and Insider Participation," "Executive Compensation," "Description of Plans," and "Compliance with Section 16(a) of the Securities Exchange Act of 1934" in the Company's 1995 definitive proxy statement which will be filed with the SEC pursuant to Regulation 14A, promulgated under the Securities Exchange Act of 1934. Notwithstanding anything to the contrary set forth in any of the Company's previous filings under the Securities Act of 1933, as amended, or the Securities Exchange Act of 1934, as amended, that might incorporate by reference future filings, including this Annual Report on Form 10-K, in whole or in part, the Report of the Management Development and Corporate Performance Committee and the Long-term Compensation Committee on Executive Compensation and the Performance Graph included in the Company's 1995 definitive proxy statement shall not be incorporated by reference into any such filings. 66 PART IV ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a) Documents filed as a part of this report: 1. Financial Statements and Schedules: See Table of Contents of Consolidated Financial Statements and Supplementary Financial Data on page 39. 2. Exhibits: 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 SEC and which are designated by reference to their exhibit numbers in prior filings are incorporated herein by reference and made a part hereof. Pursuant to Rule 15d-21 promulgated under the Securities Exchange Act of 1934, the annual reports for the Company's employee stock purchase plan and employee stock ownership plan will be furnished under cover of Form 10-K/A to the Commission when the information becomes available. 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 67 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) SCANA CORPORATION BY (SIGNATURE) s/L. M. Gressette, Jr. (NAME AND TITLE) L. M. Gressette, Jr., Chairman of the Board, Chief Executive Officer, President and Director DATE February 14, 1995 Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. (i) Principal executive officer: BY (SIGNATURE) s/L. M. Gressette, Jr. (NAME AND TITLE) L. M. Gressette, Jr., Chairman of the Board, Chief Executive Officer, President and Director DATE February 14, 1995 (ii) Principal financial and accounting officer: BY (SIGNATURE) s/W. B. Timmerman (NAME AND TITLE) W. B. Timmerman, Executive Vice President, Controller, Chief Financial Officer and Director DATE February 14, 1995 BY (SIGNATURE) s/B. L. Amick (NAME AND TITLE) B. L. Amick, Director DATE February 14, 1995 BY (SIGNATURE) s/W. B. Bookhart, Jr. (NAME AND TITLE) W. B. Bookhart, Jr., Director DATE February 14, 1995 BY (SIGNATURE) s/W. T. Cassels, Jr. (NAME AND TITLE) W. T. Cassels, Jr., Director DATE February 14, 1995 BY (SIGNATURE) s/H. M. Chapman (NAME AND TITLE) H. M. Chapman, Director DATE February 14, 1995 BY (SIGNATURE) s/J. B. Edwards (NAME AND TITLE) J. B. Edwards, Director DATE February 14, 1995 68 BY (SIGNATURE) s/E. T. Freeman (NAME AND TITLE) E. T. Freeman, Director DATE February 14, 1995 BY (SIGNATURE) s/B. A. Hagood (NAME AND TITLE) B. A. Hagood, Director DATE February 14, 1995 BY (SIGNATURE) s/W. Hayne Hipp (NAME AND TITLE) W. Hayne Hipp, Director DATE February 14, 1995 BY (SIGNATURE) s/B. D. Kenyon (NAME AND TITLE) B. D. Kenyon, Director DATE February 14, 1995 BY (SIGNATURE) s/F. C. McMaster (NAME AND TITLE) F. C. McMaster, Director DATE February 14, 1995 BY (SIGNATURE) s/Henry Ponder (NAME AND TITLE) Henry Ponder, Director DATE February 14, 1995 BY (SIGNATURE) s/J. B. Rhodes (NAME AND TITLE) J. B. Rhodes, Director DATE February 14, 1995 BY (SIGNATURE) s/E. C. Wall, Jr. (NAME AND TITLE) E. C. Wall, Jr., Director DATE February 14, 1995 69
EX-1 2 SCANA CORPORATION EXHIBIT INDEX Sequentially Numbered Pages Number 2. Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession Not applicable 3. Articles of Incorporation and By-Laws A. Restated Articles of Incorporation of SCANA Corporation as adopted on April 26, 1989 (Exhibit 3-A to Registration Statement No. 33-49145)................................................. # B. Copy of By-Laws of SCANA Corporation as revised and amended on December 15, 1993 (Exhibit 3-B to Form 10-Q for the quarter ended September 30, 1994, File No. 1-8809)................ # 4. Instruments Defining the Rights of Security Holders, Including Indentures A. Articles of Exchange of South Carolina Electric & Gas Company and SCANA Corporation (Exhibit 4-A to Post-Effective Amendment No. 1 to Registration Statement No. 2-90438).................... # B. Indenture dated as of November 1, 1989 to The Bank of New York, Trustee (Exhibit 4-A to Registration No. 33-32107)............................. # C. 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)................. # D. Fourth Supplemental Indenture dates as of April 1, 1950, to Indenture referred to in Exhibit 4C, pursuant to which the Company assumed said Indenture (Exhibit 2-C to Registration No. 2-26459)................................. # E. Fifth through Fifty-second Supplemental Indenture referred to in Exhibit 4C dated as of the dates indicated below and filed as exhibits to the Registration Statements and 1934 Act reports whose file numbers are set forth below........................................... # December 1, 1950 Exhibit 2-D to Registration No. 2-26459 July 1, 1951 Exhibit 2-E to Registration No. 2-26459 June 1, 1953 Exhibit 2-F to Registration No. 2-26459 June 1, 1955 Exhibit 2-G to Registration No. 2-26459 November 1, 1957 Exhibit 2-H to Registration No. 2-26459 September 1, 1958 Exhibit 2-I to Registration No. 2-26459 September 1, 1960 Exhibit 2-J to Registration No. 2-26459 June 1, 1961 Exhibit 2-K to Registration No. 2-26459 December 1, 1965 Exhibit 2-L to Registration No. 2-26459 # Incorporated herein by reference as indicated. 70 SCANA CORPORATION EXHIBIT INDEX Sequentially Numbered Pages Number 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-F to Registration No. 33-57955 F. 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)............................................. # G. First Supplemental Indenture to Indenture referred to in Exhibit 4-G dated as of June 1, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-49421)............................................. # H. Second Supplemental Indenture to Indenture referred to in Exhibit 4-G dated as of June 15, 1993 (Filed as Exhibit 4-G to Registration Statement No. 33-57955)............................................. # 9. Voting Trust Agreement Not Applicable # Incorporated herein by reference as indicated. 71 SCANA CORPORATION EXHIBIT INDEX Sequentially Numbered Pages Number 10. Material Contracts A. Copy of Voluntary Deferral Plan as amended through October 26, 1988 (Exhibit 10-A to Form 10-K for the year ended December 31, 1988 under cover of Form SE, File No. 1-8809)................................. # B. Copy of Supplementary Voluntary Deferral Plan as amended and restated through August 28, 1991 (Exhibit 10-B to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No. 1-8809).......................................... # C. Copy of Key Executive Severance Benefit Plan as adopted on February 28, 1990 (Exhibit 10-C to Form 10-K for the year ended December 31, 1989 under cover of Form SE, File No. 1-8809)................................. # D. Copy of SCANA Corporation Performance Share Plan as amended and restated effective February 16, 1993 (Exhibit 10-D to Form 10-K for the year ended December 31, 1992, File No. 1-8809)....................... # E. Form of Agreement under SCANA Corporation Key Employee Retention Program (Exhibit 10-E to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No. 1-8809)........................ # F. Description of SCANA Corporation Whole Life Option (Exhibit 10-F to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No. 1-8809)............................................... # G. Description of SCANA Corporation Performance Incentive Plan (Exhibit 10-G to Form 10-K for the year ended December 31, 1991, under cover of Form SE, File No. 1-8809).............................. # 11. Statement Re Computation of Per Share Earnings Not Applicable 12. Statements 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 Included herein on Page 24 # Incorporated herein by reference as indicated. 72 SCANA CORPORATION EXHIBIT INDEX Number 22. Published Report Regarding Matters Submitted to Vote of Security Holders Not Applicable 23. Consents of Experts and Counsel Consent of Deloitte & Touche LLP (Filed herewith)............ 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. 73 EX-2 3 Exhibit 12 SCANA CORPORATION CALCULATIONS OF BOND RATIO FOR THE YEAR ENDED DECEMBER 31, 1994 (Thousands of Dollars) Net earnings(1) $331,551 Divide by annualized interest charges on: Bonds authenticated under the Company's First and Refunding Mortgage Bond Indenture $42,901 Other indebtedness(1) $51,224 Total annualized interest charges $ 94,125 Bond ratio 3.52 (1) As defined under the Company's First and Refunding Mortgage Bond Indenture (Old Mortgage). 74 SCANA CORPORATION CALCULATION OF NEW BOND RATIO FOR THE YEAR ENDED DECEMBER 31, 1994 (Thousands of Dollars) Net earnings(1) $448,766 Divide by annualized interest charges on: Bonds authenticated under the Company's First Mortgage Bond Indenture $49,513 Other indebtedness(1) $43,096 Total annualized interest charges $ 92,609 Pro Forma New Bond Ratio 4.85 (1) As defined under the Company's Collateral Trust Mortgage Indenture (New Mortgage). 75 SCANA CORPORATION CALCULATIONS OF PREFERRED STOCK RATIO FOR THE YEAR ENDED DECEMBER 31, 1994 (Thousands of Dollars) Net Earnings (1) $244,593 Divide by annualized interest charges on: Bonds authenticated under SCE&G's mortgage bond indentures $92,414 Other indebtedness (1) $ 8,477 Preferred Dividend Requirements $ 5,887 Total annualized interest charges $106,778 Preferred stock ratio 2.29 (1) As defined under SCE&G's Restated Articles of Incorporation. 76 SCANA CORPORATION COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES For Each of the Five Years Ended December 31, 1994 (Thousands of Dollars) Years Ended December 31, 1994 1993 1992 1991 1990 Fixed Charges as defined: Interest on long-term debt.................. $106,573 $ 96,916 $ 92,178 $ 87,854 $ 84,563 Amortization of debt premium, discount and expense (net).............................. 2,230 1,779 874 835 681 Other interest expense...................... 6,749 8,672 8,819 7,649 10,552 Interest component of rentals............... 2,717 2,853 929 897 951 Total Fixed Charges (A)................. $118,269 $110,220 $102,800 $ 97,235 $ 96,747 Earnings, as defined: Income...................................... $157,156 $174,198 $124,063 $142,557 $188,514 Income taxes................................ 81,736 91,562 60,252 75,325 108,202 Total fixed charges above................... 118,269 110,220 102,800 97,235 96,747 Total Earnings (B)...................... $357,161 $375,980 $287,115 $315,117 $393,463 Ratio of Earnings to fixed charges (B/A)...... 3.02 3.41 2.79 3.24 4.07
77 EX-3 4 EXHIBIT 23 INDEPENDENT AUDITORS' CONSENT We consent to the incorporation by reference in Post-Effective Amendment No. 4 to Registration Statement No. 2-92743 of SCANA Corporation on Form S-8, Post-Effective Amendment No. 4 to Registration Statement No. 2-90618 on Form S-8, Post-Effective Amendment No. 1 to Registration Statement No. 33-32107 on Form S-3, Registration Statement No. 33-44317 on Form S-8, Post-Effective Amendment No. 1 to Registration Statement No. 33-43636 on Form S-3, Registration Statement No. 33-49333 on Form S-8, Post Effective Amendment No. 1 to Registration Statement No. 33-55861 on Form S-3, and Registration Statement No. 33-56923 on Form S-8 of our report dated February 6, 1995 appearing in this Annual Report on Form 10-K of SCANA Corporation for the year ended December 31, 1994. s/Deloitte & Touche LLP DELOITTE & TOUCHE LLP Columbia, South Carolina March 10, 1995 78 EX-4 5 [ARTICLE] OPUR1 [LEGEND] THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONSOLIDATD BALANCE SHEET AS OF DECEMBER 31, 1994 AND THE CONSOLIDATED STATEMENTS OF INCOME AND RETAINED EARNINGS AND OF CASH FLOWS FOR THE TWELVE MONTHS ENDED DECEMBER 31, 1994 AND IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS. [/LEGEND] [PERIOD-TYPE] 12-MOS [FISCAL-YEAR-END] DEC-31-1993 [PERIOD-END] DEC-31-1994 [BOOK-VALUE] PER-BOOK [TOTAL-NET-UTILITY-PLANT] 3,293,667 [OTHER-PROPERTY-AND-INVEST] 395,929 [TOTAL-CURRENT-ASSETS] 340,332 [TOTAL-DEFERRED-CHARGES] 363,200 [OTHER-ASSETS] 0 [TOTAL-ASSETS] 4,393,128 [COMMON] 886,770 [CAPITAL-SURPLUS-PAID-IN] 0 [RETAINED-EARNINGS] 523,668 [TOTAL-COMMON-STOCKHOLDERS-EQ] 1,410,438 [PREFERRED-MANDATORY] 49,528 [PREFERRED] 26,027 [LONG-TERM-DEBT-NET] 1,537,624 [SHORT-TERM-NOTES] 183,027 [LONG-TERM-NOTES-PAYABLE] 0 [COMMERCIAL-PAPER-OBLIGATIONS] 0 [LONG-TERM-DEBT-CURRENT-PORT] 38,055 [PREFERRED-STOCK-CURRENT] 2,418 [CAPITAL-LEASE-OBLIGATIONS] 0 [LEASES-CURRENT] 0 [OTHER-ITEMS-CAPITAL-AND-LIAB] 1,146,011 [TOT-CAPITALIZATION-AND-LIAB] 4,393,128 [GROSS-OPERATING-REVENUE] 1,322,062 [INCOME-TAX-EXPENSE] 94,510 [OTHER-OPERATING-EXPENSES] 967,999 [TOTAL-OPERATING-EXPENSES] 1,062,509 [OPERATING-INCOME-LOSS] 259,553 [OTHER-INCOME-NET] 5,998 [INCOME-BEFORE-INTEREST-EXPEN] 265,551 [TOTAL-INTEREST-EXPENSE] 108,397 [NET-INCOME] 157,154 [PREFERRED-STOCK-DIVIDENDS] 5,955 [EARNINGS-AVAILABLE-FOR-COMM] 151,199 [COMMON-STOCK-DIVIDENDS] 133,911 [TOTAL-INTEREST-ON-BONDS] 82,980 [CASH-FLOW-OPERATIONS] 296,705 [EPS-PRIMARY] 3.19 [EPS-DILUTED] 0
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